BEFORE THE
PENNSYLVANIA PUBLIC UTILITY COMMISSION
Pennsylvania Public Utility Commission
U.S. Department of Defense & Federal
Executive Agencies
PPL Industrial Customer Alliance
Office of Small Business Advocate
Office of Consumer Advocate
Anthony J. Graziano
Brenda Hoover
Eric Joseph Epstein
Victoria K. Mackin, et al.
Cheryl & Jeremy Ebert
Martha Wells
Margaret M. Stuski
Wal-Mart Store East, LP.
Pennsylvania Energy Consortium
Donald F. McGarrigle
Curvin L. Snyder
William J. Junkin, III
Philip A. Trump
Pennsylvania Retailers Association
Christy Meyers
v.
PPL Electric Utilities Corporation
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RECOMMENDED DECISION
Before
Allison K. Turner
Administrative Law Judge
R-00049255
R-00049255C0001
R-00049255C0002
R-00049255C0003
R-00049255C0004
R-00049255C0005
R-00049255C0006
R-00049255C0007
R-00049255C0008
R-00049255C0009
R-00049255C0010
R-00049255C0011
R-00049255C0012
R-00049255C0013
R-00049255C0014
R-00049255C0015
R-00049255C0016
R-00049255C0017
R-00049255C0018
R-00049255C0019
TABLE OF CONTENTS
Page
I.
HISTORY OF THE CASE
1
II.
INTRODUCTION
5
III.
DESCRIPTION OF THE COMPANY
9
IV.
RATE BASE
12
V.
VI.
1.
Prepaid Postage
13
2.
Cash Working Capital
15
3.
Projected Plant Balances
17
4.
Capitalized Portion of Pension Expense
18
REVENUES
18
1.
Unbilled Revenues
19
2.
Late Payment Fees
21
3.
Sales Forecast
24
4.
Distribution System Improvement Service Charge
32
A.
Need for the DSIC
35
B.
Authority for a DSIC
39
C.
Additional Arguments
43
D.
Additional Conclusions on the DSIC
46
EXPENSES
47
1.
Introduction – Rate Caps
47
2.
Hurricane Isabel
54
3.
Employees Severance Costs Resulting from
Implementation of the AMR Program
58
4.
Epstein Adjustments
62
5.
Pension Expense
63
6.
US DOD’s Proposed Adjustment to Injuries
and Damages Expense
66
US DOD’s Proposed Adjustment to PPLEU’s
Employee Health Insurance Expense
67
8.
PPLEU’s Revised Environmental Expense Claim
68
9.
Proposed Reductions in OnTrack and WRAP Funding
by OCA and OTS
70
OCA’s Additional Expense Adjustment
73
A.
Interest Synchronization
76
11.
OTS Additional Expense Adjustments
76
12.
Sustainable Energy Fund (SEF)
77
7.
10.
VII.
VIII.
TAXES
88
1.
89
Capital Stock Tax
RATE OF RETURN
94
1.
Introduction
94
2.
Discussion
97
3.
Capital Structure
98
4.
Cost of Debt and Cost of Preferred Stock
101
5.
Return on Common Equity (ROE)
101
A.
Use of Natural Gas Barometer Groups
103
B.
DCF
107
1
IX.
C.
The Electric Barometer Groups
110
D.
CAPM
113
E.
Comparable Earnings
114
F.
“Wires Only” – More or Less Risky?
115
G.
Leverage Adjustment
115
H.
Summary and Conclusions
117
RATE STRUCTURE
1.
2.
3.
122
Rate Structure - Transmission Service Charge
124
A.
Reconciliation
127
B.
Positions of the Parties
130
C.
Reconciliation Methodologies
134
D.
Comparative Allocation Summary
137
Rate Structure – Distribution
140
A.
Introduction
140
B.
Cost of Service Studies
142
C.
The Company’s Proposed Revenue Increase
Allocation
145
D.
Scale Back is Fairer than Reallocation
148
E.
The Alternative Revenue Allocations Should
Be Rejected
149
Rate Design – Increased Customer Charges
152
A.
Rate RS Rate Design
152
B.
Rate RTS Rate Design
155
C.
PLUG
156
2
X.
UNIVERSAL SERVICE AND CUSTOMER/COMMUNITY
PROGRAMS
160
1.
Introduction
160
2.
Funding for OnTrack and Wrap
163
3.
$150.00 Arrearage Eligibility Requirement for OnTrack
167
4.
Mandatory or Proactive Budget Billing Program
168
5.
Operation HELP’s Funding and Implementation
171
6.
Community Betterment Initiative (CBI)
172
7.
Requests to Reallocate Universal Service Program Costs
173
XI.
RETAIL COMPETITION ISSUES
176
XII.
PUBLIC INPUT HEARINGS
179
XIII. ORDER
182
XIV. TABLES
185
3
I.
HISTORY OF THE CASE
On March 29, 2004, PPL Electric Utilities Corporation (PPL, PPLEU, or the
Company) filed Supplement No. 38 to Tariff Electric-Pa.P.U.C. No. 201 to become effective
June 1, 2004, proposing to increase its retail distribution rates by $164.4 million in additional
revenues, based on a future test year ending December 31, 2004. Additionally, PPL informed
the Commission that transmission charges reflected in retail rates are expected to increase by
approximately $57.2 million. These charges arise under FERC-regulated PJM Open Access
Transmission Tariffs (OATTs). The combination will produce an overall increase of $221.6
million, representing an increase in annual revenues of 8.1%.
Paul E. Russell, Esq. presented the filing on behalf of the Company.
During the course of the proceeding, PPLEU agreed to certain adjustments raised
by other parties, resulting in a reduction of its requested distribution rate increase from $164.4
million to $159.4 million. These adjustments are reflected in the Company’s final accounting
Exhibit Future 1 (Revised).
On May 7, 2004, the Commission instituted an inquiry and investigation to
determine the fairness, reasonableness and justness of rates named in Supplement No. 38 to
Tariff Electric-Pa.P.U.C. No. 201, and ordered that the investigation shall include consideration
of the lawfulness, justness and reasonableness of PPL’s existing rates, rules and regulations. The
Commission ordered that, pursuant to 66 Pa.C.S. §1308(d), the filing be suspended by operation
of law on June 1, 2004 until January 1, 2005, and that PPL cannot increase distribution rates
before the end of 2004 due to the transmission and distribution rate cap.
On April 13, 2004, the Northeast Delegation of the House of Representatives,
chaired by the Honorable Phyllis Mundy, sent a letter to the Chief Administrative Law Judge
requesting that a public hearing be held in a central location in Northeastern Pennsylvania on
PPL’s recent rate increase proposal. Every member of the Northeast Delegation signed the letter.
Richard A. Kanaskie, Esq., filed a Notice of Appearance on behalf of the Office
of Trial Staff (OTS).
John H. Isom, Michael W. Gang and David MacGregor, Esq., of Morgan Lewis
and Bockius filed entries of appearance on behalf of PPL.
The following entities and individuals filed formal complaints against the rate
increase and were assigned docket numbers accordingly: US Department of Defense & Federal
Executive Agencies (USDOD), R-00049255C0001; PPL Industrial Customer Alliance
(PPLICA), R-00049255C0002; Office of Small Business Advocate (OSBA), R-00049255C0003;
Office of Consumer Advocate, (OCA), R-00049255C0004; Anthony J. Graziano, R00049255C0005; Brenda Hoover, R-00049255C0006; Eric Joseph Epstein, R-00049255C0007;
Victoria Mackin, R-00049255C0008; Cheryl & Jeremy Ebert, R-00049255C0009; Martha Wells,
R-00049255C0010; Margaret Stuski, R-00049255C0011; WAL-MART Store East, LP, R00049255C0012; Pennsylvania Energy Consortium, R-00049255C0013; Donald McGarrigle, R00049255C0014; Curvin Snyder, R-00049255C0015; William J Junkin, III, R-00049255C0016;
Philip A. Trump, R-00049255C0017; and Pennsylvania Retailers Association, R00049255C0018. PPL filed Answers to all these complaints, but did not oppose the participation
of any complainant, with the exception of Margaret Stuski (C0011). PPLEU filed a Motion to
Dismiss this complaint along with its Answer. The ALJ granted PPLEU’s Motion to Dismiss in
an Initial Decision served by the Commission on September 13, 2004, with Exceptions to be
filed October 4, 2004.
The following entities filed Petitions to Intervene that were granted: the
International Brotherhood of Electrical Workers, Local 1600 (IBEW); the Commission on
Economic Opportunity (CEO); PECO Energy Company (PECO); West Penn Power Company
d/b/a Allegheny Power (Allegheny); the Clean Air Council; the Sustainable Energy Fund (SEF);
the Mid Atlantic Power Supply Association (MAPSA); UGI Utilities, Inc.(UGI); Public Lighting
Users Group (PLUG); and, Citizens for Pennsylvania’s Future, et al. (CFPF or PennFutures).
PPL responded to each of these Petitions, but did not oppose the participation of any of the
Petitioners.
2
Of these intervenors, the following did not submit a witness, attend hearings and
cross examine witnesses, or submit a main brief: PECO; Allegheny; UGI; and IBEW. These
intervenors will be dismissed.
The following entities filed Petitions to Intervene that were denied for lack of
standing: Duquesne Light Company; Sustainable Development Fund (SDF); and Metropolitan
Edison, Pennsylvania Electric Company and American Transmission Systems.
By April 26, 2004, rate protests had been filed by various individuals, and had
been placed in the Public Comment file. Since that time, many more rate protests have been
filed and placed in the Public Comment file.
On May 10, 2004, the Office of Administrative Law Judge (OALJ) served a
notice scheduling an Initial Prehearing Conference to be held in Harrisburg on May 19, 2004 at
2:00 p.m. The case was assigned to Administrative Law Judge Allison K. Turner (ALJ) for
preliminary rulings, hearing and decision, and to ALJs Susan Colwell and Ember Jandebeur for
hearings.
On May 12, 2004, the ALJ served her first Prehearing Order, establishing certain
basic procedures to be followed before and during the Initial Prehearing Conference.
The Initial Prehearing Conference was convened by the ALJ as scheduled on May
19, 2004, in Harrisburg, PA. The following parties were represented and participated: PPL;
OTS; OCA; OSBA; PPLICA; USDOD; IBEW, Local 1600; Eric Epstein; Commission on
Economic Opportunity (CEO); Sustainable Energy Fund (SEF); Citizen’s for Pennsylvania’s
Future (CFPF or PennFutures); MAPSA; Clean Air Council (CAC); Public Lighting User Group
(PLUG); Allegheny Power; Duquesne Light Company (Duquesne); PECO; and, UGI Utilities,
Inc. (UGI). Many of these same parties also filed Prehearing Memoranda.
3
The ALJ filed a second Prehearing Order establishing a procedural schedule, and
establishing certain procedural rules to be followed during the proceeding.
Between the Prehearing Conference and the middle of July, the parties held an
informal discovery conference at PPLEU in Allentown, and several settlement conferences and
discussions. However, no agreements were reached.
A total of nine Public Input Hearings (PI Hearings or Hearings) were held
throughout PPL’s service territory. These Hearings were held in Lancaster, Harrisburg,
Bethlehem, Allentown, Scranton, Wilkes Barre, Williamsport, and, telephonically in Harrisburg.1
ALJ Susan Colwell conducted the PI Hearings in Lancaster and Harrisburg. ALJ Ember
Jandebeur conducted the PI Hearings in Scranton and Wilkes-Barre.
Each Public Input Hearing was attended by a representative of the Company,
OTS, OSBA and OCA. A transcript of each Public Input Hearing is part of the record. It is
noted that the Northeast Delegation, chaired by the Honorable Representative Phyllis Mundy,
had its statement read into the record by its executive director at the Wilkes Barre session. The
relevant testimony begins on page 250 of the transcript.
Technical evidentiary hearings were held in Harrisburg the week of August 9,
2004 culminating with the final, aforementioned Public Input Hearing. During that time,
testimony and exhibits of all the active parties were entered into the record. A total of 1,135
pages of transcript were produced (including the PI Hearings), and the record closed on August
13, 2004 with all active parties signifying that a complete record had been developed.
On September 15, 2004, Christy Meyers filed a formal complaint against the rate
increase which was docketed at R-00049255C0019. On September 23, 2004, PPLEU filed its
Answer to the Complaint.
1
The second Public Input Hearing in Harrisburg was conducted telephonically on the last day of
evidentiary hearings to allow an opportunity to be heard for Complainants whose complaints had not been docketed
timely, preventing them from receiving notice of the PI Hearings.
4
PPLEU and OSBA both requested transcript corrections. The ALJ served two
Orders granting most of the requested corrections.
The following parties filed Main Briefs on September 2, 2004: PPLEU; OTS;
OCA; OSBA; US DOD; PPLICA; PennFutures (CFPF); CAC; SEF; Eric Epstein (EE); and,
CEO. References to the Briefs will be designated by the abbreviated party name and “MB at”.
References to the transcript will be designated as “Tr.” followed by the page number.
References to testimony and exhibits will be designated by abbreviated party name and “St” or
“Exh” followed by the initials and numbers used to identify them.
The following parties submitted Reply Briefs on September 13, 2004: PPLEU;
OTS; OCA; OSBA; PPLICA; PennFutures (CFPF); CAC; SEF; and, CEO. References to the
Briefs will be designated by the abbreviated party name and “RB at”. References to the
transcript will be designated as “Tr.” followed by the page number. References to testimony and
exhibits will be designated by abbreviated party name and “St” or “Exh” followed by the initials
and numbers used to identify them.
The ALJ may not have discussed each and every issue, but omission of an issue
does not equate to approval of any point of view or adjustment.
The ALJ wishes to commend the parties on their professionalism in submitting
pleadings and in their conduct at the hearings, and on the high quality of their Briefs. She has
relied on the Briefs extensively in preparing this Recommended Decision. The ALJ found
Volume II of OCA’s Main Brief (Unpublished documents)to be particularly helpful.
II.
INTRODUCTION
Much has been said about the precedent-setting nature of this case. The most
important precedent to be set here is the retention of the Commission’s flexibility in key areas of
rate setting, such as rate of return and rate structure, and the potential for expanding flexibility
5
into other areas, such as additional automatic adjustment clauses. There may be other areas not
foreseen at the moment.
The Company emphasizes that it is in, or entering into, a period of transition. The
transition period began with the first restructuring filing, and has continued through the period of
the transmission and distribution rate cap, during which PPLEU became a “wires only” electric
utility, and will continue through the next period without transmission and distribution caps but
with the continuing generation rate cap, and beyond. Traditional rate of return regulation may
have to stretch to accommodate deregulation.
It is true that PPLEU is in the throes of a transition period, as are all other
restructured electric utilities, no matter what path they have taken. It is true as well that the
Commission, as the regulator, is also deeply engaged in this same transition period.
The Company, especially, contends that the Commission’s actions will send
important messages to the “sources of capital” about the future of regulation in Pennsylvania.
This may be true, but it is likely that “capital” recognizes that this is one step in a multi-step
process of moving from full regulation of structurally integrated electric utilities to an evolving
restructured industry under regulation that is also evolving to fit with the new industry. In 1995,
PP&L was a structurally integrated utility owning a major nuclear generating plant. Today, it is
PPLEU, and it is a “wires only” distribution delivery utility.
The Pennsylvania Public Utility Commission has long been known for high
quality regulation that gives consideration to both the utility and its customers, and will continue
to be so in this new era.
Meanwhile, OCA and OTS remind us that the Commission must decide its rate
cases on a record, and there must be sufficient evidence to support its rulings. In fact, they most
pointedly remind us that the utility has the burden of proof here. Section 315(a) of the Public
Utility Code provides that:
6
Reasonableness of rates.—In any proceeding upon the motion of
the Commission, involving any proposed or existing rate of any
public utility, or in any proceeding upon complaint involving any
proposed increase in rates, the burden of proof to show that the rate
involved is just and reasonable shall be upon the public utility.
66 Pa.C.S. §315(a)
This principle has been interpreted by the Commonwealth Court as follows:
Section 315(a) of the Public Utility Code, 66 Pa.C.S. §315(a),
places the burden of proving the justness and reasonableness of a
proposed rate hike squarely on the public utility. It is wellestablished that the evidence adduced by a utility to meet this
burden must be substantial. (Citations omitted.)
Lower Frederick Twp. v. Pa. PUC, 48 Pa. Commw. Ct. 222, 226-27, 409 A.2d 505, 507 (1980)
(emphasis added). See also, Brockway Glass v. Pa. PUC, 63 Pa. Commw. Ct. 238, 437 A.2d
1067 (1981). OCA MB at 7; OTS MB at 6.
In the context of a high bill complaint, including a meter reading, the
Pennsylvania Supreme Court ruled on the burden of proof of the complainant Burleson, not the
utility. The Court found that the party with the burden of proof (the complainant, Burleson) has
a formidable task before its position can be adopted by the Commission. Even where a party has
established a prima facie case, the litigant still must establish that “the elements of that cause of
action are proven with substantial evidence which enables the party asserting the cause of action
to prevail, precluding all reasonable inferences to the contrary.” Burleson v. Pa. PUC, 501 Pa.
433, 461 A.2d 1234 (1983) (emphasis added).
With specific reference to base rate proceedings, it is well settled at the
Commission and in the courts that the utility’s burden of establishing the justness and
reasonableness of every component of its rate request is an affirmative one that remains with the
public utility throughout the course of the proceeding. This burden does not shift to intervenors
challenging a requested rate increase. There is no similar burden placed on an intervenor to
7
disprove a company’s claim. See e.g., Berner v. Pa. P.U.C., 382 Pa. 622, 116 A.2d 738 (1955)
(Berner). In Berner, the Pennsylvania Supreme Court stated:
[T]he appellants did not have the burden of proving that the plant
additions were improper, unnecessary or too costly; on the
contrary, that burden is, by statute, on the utility to demonstrate the
reasonable necessity and cost of the installations and that is the
burden which the utility patently failed to carry.
Berner, 382 Pa. at 631, 116 A.2d at 744.
This standard has been recognized by the Commission in its rate determinations:
The Respondent, Equitable has the burden of persuasion in the
issue of the reasonableness of an expense level. Respondent must
affirmatively establish, on the record, that the test year claim is a
reasonable and appropriate amount.
Pa. P.U.C. v. Equitable Gas Co., 57 Pa. P.U.C. 423, 471 (1983) (emphasis added); accord,
University of Pennsylvania v. Pa. PUC, 86 Pa. Commw. 410, 485 A.2d 1217 (1984).
The OCA submits that it is incumbent upon the Company to affirmatively prove
the reasonableness of every element of its claim. The OCA submits that a number of PPL’s
claims must fail based on the Company’s failure to sustain its burden of proof. Moreover, the
OCA submits that the OCA’s adjustments to PPL’s claims are credible and reasonable and
should be adopted by the Commission.
The Commission and the Courts have clearly held that the burden of proof does
not shift to the party challenging a requested rate increase. While the burden of going forward
may shift, the burden of finally and convincingly establishing the justness and reasonableness of
every component of a requested rate increase remains on the utility. The opposing parties have
no such burden. As stated by the Pennsylvania Supreme Court in Berner v. Pa. P.U.C., 382 Pa.
622, 631, 116 A.2d 738, 744 (1955):
8
[t]he appellants did not have the burden of proving that the plant
additions were improper, unnecessary or too costly; on the
contrary, that burden is, by statute, on the utility to demonstrate the
reasonable necessity and cost of the installations . . . .
On this subject, the Commission has ruled as follows:
[t]here is no presumption of reasonableness which attached to a
utility’s claim, at least none which survives the raising of credible
issues regarding a utility’s claims. A utility’s burden is to
affirmatively establish the reasonableness of its claim. It is not the
burden of another party to disprove the reasonableness of a utility’s
claims.
(Emphasis added) Pa. P.U.C. v. Equitable Gas Co., 57 PA PUC 423, 444 (fn. 37) (1983).
The ALJ emphasizes the need for opposing parties to raise credible claims.
Asserting personal opinions, repeating widely held beliefs, and presenting newspaper articles or
articles off the internet do not necessarily rise to the level of credible claims.
Moreover, the ALJ opines that parties challenging the Company’s proposed rate
structure and cost allocations with cost of service studies of their own, and proposed different
cost allocations, also have a burden of proof, as if they were complainants against the
Company’s proposals. These parties must support their proposals with substantial evidence if
the Commission is to adopt their proposals in place of the Company’s rate designs.
III.
DESCRIPTION OF THE COMPANY
In 1920, PP&L was founded through consolidation of eight electric companies as
a direct subsidiary of Lehigh Power Securities Corporation (Lehigh Power) and an indirect
subsidiary of Electric Bond and Share Company (Electric Bond).
Throughout the 1920s and 1930s, PPL continued to acquire and merge with other
electric companies.
9
In 1939, Lehigh Power Securities Corporation was dissolved, and PP&L became
a subsidiary of National Power & Light Company (National Power) and remained an indirect
subsidiary of Electric Bond.
Between 1945 and 1947, PP&L became independent as a result of a multi-step
process carried out under the Public Utility Holding Company Act of 1935 (PUHCA) and
National Power and Electric Bond divested themselves of PP&L ownership, and PP&L stock
was sold to the public. There followed another period of acquisitions and mergers.
In 1994, PP&L Resources, Inc. was incorporated as an energy and utility holding
company. PP&L Resources became the parent of PP&L. PP&L’s name was changed to PP&L,
Inc.
In 2000, PP&L, Inc. became PPL Electric Utilities Corporation (PPLEU), and the
name of the holding company became PPL Corporation (PPL Corp).
On July 1, 2000, PPL Corp. and PPLEU completed a corporate realignment in
order to effectively separate PPLEU’s regulated transmission and distribution operations from its
deregulated generation operations. There are a number of other subsidiaries, including H. T.
Lyons, Inc. (see Stuski Complaint and Answer), PPL Generation, and those mentioned below.
In 2001, PPL Corp completed a strategic initiative to confirm the structural
separation of PPLEU from PPL Corp’s and PPLEU’s other affiliated companies. PPLEU is now
a “wires only” company.
Under the new corporate structure, PPL Services Corporation, as a result of the
realignment, provides various administrative and general services to PPLEU and other
subsidiaries of PPL Corp. These services include Office of General Counsel, Human Resources,
Information Services, Auditing, and Community Affairs. Services are provided under a contract
signed in 1995. Id., II-D-8.
10
Another sister subsidiary, PPL Solutions, LLC provides various services to
PPLEU for energy supplier coordination. These services include communications, energy load
scheduling, and reconciliation services. Id.
PPLEU also has a long-term wholesale “full requirements” supply contract at
fixed prices with its corporate affiliate, PPL Energy Plus through the remainder of this decade.
OCA St 3 at 18
PPLEU presently serves a 10,000 square mile territory in 29 counties of centraleastern Pennsylvania - from Bristol and Bensalem and Dingman and Milford at the extreme
eastern end of the territory, on the border with New Jersey; to Williamsport and Lock Haven and
beyond on the extreme western reaches of the territory in Central Pennsylvania. This territory
contains extensive agricultural and industrial sections, as well as over 800 major communities,
including the cities of Allentown, Bethlehem, Harrisburg, Lancaster, Scranton, Wilkes-Barre
and, as stated before, Williamsport. See Exhibit Regs §53.52, §53.53, 1-B-1 for History, Maps,
and list of territory covered by PPLEU’s Tariff.
PPLEU serves approximately 1.3 million customers. It describes some of its
infrastructure and operations as follows:
Specifically, PPLEU owns 889,000 poles, 36,500 miles of
power lines (including 6,700 miles of underground lines) and over
335 substations/switching stations. The Company must maintain,
repair and replace those facilities as needed, and anticipates it will
be required to invest approximately $900 million in capital
improvements over the next five years. Approximately 96% of
this five-year capital budget is non-discretionary, with more than
half of the spending required to accommodate growth, including
both new customer connections and additional system capacity.
PPLEU’s operating expenses also are substantial and also
continue to increase. In an average year, PPLEU connects or
transfers service for 33,500 customers, at an average cost of
approximately $2,300 for each new connection. The Company
answers 1.8 million telephone calls, replaces 20,000 street lights
11
and trims trees along more than 4,100 miles of power lines.
Finally, PPLEU processes approximately 16 million bills annually.
The cost of labor, poles, wires, tools, vehicles and equipment
required to maintain this level of service has increased throughout
the rate cap period and will continue to increase in the foreseeable
future.
Exhibit Future 1 (Revised) A-1 at 7.
IV.
RATE BASE
When the rate increase request was initially filed, the Company claimed that the
PAPUC jurisdictional rate base as of December 31, 2004 was $1,842,744,000.00, shown on Exh
Future 1(Orig), Sched C-1. Subsequently, the Company accepted a number of adjustments
proposed by the parties. As shown on PPLEU Exh. Future 1 (Revised), Sch. C-1, PPLEU now
claims Pennsylvania jurisdictional rate base as of December 31, 2004, of $1,837,003,000.00:
This amount reflects several adjustments made in the
course of this proceeding that have reduced the number of litigated
issues related to rate base. These adjustments include:
(1)
(2)
(3)
(4)
(5)
Elimination of the amortization of Power
Management System (“PMS”) software (PPLEU Ex.
Future 1 (Revised), Sch. C-2, p. 2), which now has
been accepted by the OCA (Tr. 489-490);
Adjustments to post retirement benefits, pension and
the Supplemental Executive Retirement Plan
(“SERP”) (PPLEU Ex. Future 1 (Revised), Sch. C2a, p. 1);
Elimination of plant held for future use based on
agreement of parties that PPLEU may accrue
AFUDC on such plant (PPLEU Ex. Future 1
(Revised), Sch. C-3, p. 1);
Adjustments to the projected level of customer
deposits (Tr. 480); and
Corrections to cash working capital (PPLEU Ex.
Future 1 (Revised), Sch. C-4, p. 2).
All of these adjustments are reflected in the Company’s final
accounting exhibit – Future 1 (Revised).
12
PPLEU MB at17
PPLEU’s original cost plant in service is set forth at Exh Future (Rev) Sched C-2
at 1 in the amount of $4,424,095,000.00. PPLEU’s original cost reserve for depreciation is
$1,709,721,000.00. Id. Sched C-2 at 2
There remain several disputed adjustment issues concerning rate base to be
decided in this proceeding. OCA proposes to remove prepaid postage from rate base. OCA
proposes several other adjustments related to PPLEU’s universal service programs as they
impact cash working capital, but these are eventually addressed as universal service issues.
OCA’s adjustments would result in a recommended rate base of $1,829,071,000.00. OCA RB at
7
US DOD proposes that only the average of plant in service as of December 31,
2003 and that in service on December 31, 2004 be allowed as rate base.
OTS argues that PPLEU’s rate base must be adjusted by removal of the
capitalized portion of its Pension Expense claim. OTS RB at 5
1.
PREPAID POSTAGE
According to the Company, its cash working capital claim includes a claim for the
net lag in recovery of operating expenses based upon a lead-lag study and a separate claim for
average prepayments. PPLEU Ex. Future 1 (Revised), Sch. C-4. “In accordance with this longstanding practice, PPLEU has included components of its postage expense in both the lead-lag
study and in the average prepayment balances.” The Company argues that “there are two
entirely separate, distinct and non-overlapping components of PPLEU’s working capital claim
for postage expense.” PPLEU MB at 18-19
13
The first component is “the period of time between when PPLEU pays the United
States Postal Service for postage and the time when such bills are mailed to customers.” This is
included in the average prepayment balance of postage. The second is “the period of time
between the mailing of bills, when the postage is used and expensed on the Company’s income
statements, and the time when customers pay their bills, thereby reimbursing PPLEU for its
postage expense. It is this second component of the cash working capital requirement that is
reflected in the lead-lag study.” Id.; OCA St 5-R at 11-12
According to OCA, PPLEU’s inclusion of a claim for prepaid postage in the
average prepayment balances as well as its inclusion of a postage claim in the lead/lag study
results in a double recovery. OCA RB at 7. Although the Company argues that these two
components are measuring different periods of time, OCA asserts that this argument is incorrect.
See OCA St. 1-S at 5. PPL disagrees that a double-count is occurring. PPLEU MB at 19.
OCA witness Morgan disagrees with witness Kleha and explains: “only the
lead/lag study includes a measure of time ... in calculating the amount of working capital to be
included in rate base. The prepaid balance is simply the balance at the end of the month, and
does not attempt to measure any time interval.” OCA St 1-SR at5-6
When lead days are applied to an expense it measures prepayment
of an expense, and it has the effect of increasing the allowance for
cash working capital. The lead/lag study is based upon measuring
time intervals and converting the effect of the interval into working
capital requirements. That working capital amount is then added
to rate base for the company to earn a return on it.
In this instance the Company has calculated the lead days from the
prepayment date to the date the postage was used. Consequently,
the working capital for that period of time has been fully captured
by the lead/lag study, and there is no need to add prepaid postage
to rate base.
OCA St. 1-S at 5-6.
14
According to the Company, this statement is incorrect. It avers that the period of
time it captures in the lead/lag study is from the date the bills are mailed to the date it receives
payment from the customers. The ALJ does not understand why this period is classified as
postage. It seems to be a revenue lag, rather than a postage lead or lag, because the key ending
date is the receipt of revenue. The Company has calculated the average lag in receipt of revenue
as 45.5 days. Exh Historic 1, Scheds C-4 at 2 of 12
If OCA is correct, and the Company has included the balance of prepaid postage
in rate base to reflect the fact that it purchases postage in advance of using it to send bills, it has
not cited any source for this information. The OCA does not dispute that PPL has a prepaid
postage balance. However, OCA asserts that the manner in which PPL has measured the postage
lead for its lead/lag study fully accounts for this prepayment. Based on the Company’s
averments, OCA is not correct. In its lead/lag study, PPL has measured the expense lead for
postage expense based on the time it sends bills to its customers until the time the customers pay
those bills.
OCA asserts that, based on the evidence submitted by the Company, PPLEU’s
claim for prepaid postage expense of $361,000 should be removed from rate base. The ALJ
cannot agree with the OCA’s analysis because the Company states its evidence differently. If the
OCA’s statement of the evidence were correct, she would agree with OCA’s analysis that
allowing this claim would result in a double recovery, and reject the Company’s rationale that it
is actually covering two separate time periods.
However, because OCA does not cite to any evidence, and the Company has
presented the testimony of witness Kleha, the ALJ recommends that the Commission does not
grant OCA’s adjustment.
2.
CASH WORKING CAPITAL
OTS analyzed the Company’s cash working capital (CWC) claim carefully and at
length. OTS St 2 at 45-51. As a result, OTS recommended a CWC “allowance of $22,787,000
15
in this proceeding as opposed to the Company’s claim of $23,205,000. This recommendation
represents a reduction of $418,000....” OCA recommended a similar adjustment. OCA MB at
16-17. After reviewing OTS and OCA proposed adjustments, the Company recognized a need
for reduction of its claim in the amount of $389,000, detailed in the Company’s testimony and
exhibits. PPLEU St 5-R at 11; Exh Future-1 (Rev), Scheds C-4 at 2 and 3. For the purposes of
this proceeding, OTS accepts the reduction of $389,000 to the Company’s CWC claim.
Therefore, the ALJ recommends that the Commission also accept this reduction.
In its Reply Brief at 9, OCA states its CWC claim as follows:
In its Main Brief, the Company takes issue with various
expense adjustments resulting from the OCA adjustments relating
to, inter alia, PPL’s universal service programs. These issues are
addressed in the Company’s Main Brief relating to the individual
expenses impacting the Company’s cash working capital claim and
will be addressed in the particular expense portions of the OCA’s
Reply Brief. The OCA submits that PPL’s cash working capital
claim should be [adjusted by] $7,571,000 after the Pennsylvania
jurisdictional allocation factor is applied. OCA M.B. at 17.
The ALJ cannot recommend this adjustment to the Commission because the way
it is developed is unclear. OCA MB at16-17. However, it appears to include an adjustment to
the number of lead/lag days the Company calculated for materials and supplies expense. This
adjustment was acknowledged and included in the $389,000 adjustment set forth by witness
Kleha in response to OTS and OCA. 5-R at 11. Including it again here would be double
counting.
However, OCA’s final request regarding cash working capital is that in its final
Order, the Commission adjust the Company’s cash working capital claim so that it is consistent
with the Commission’s findings regarding the Company’s final CWC claims. The ALJ does
recommend this course of action.
16
3.
PROJECTED PLANT BALANCES
In accordance with long-standing Commission practice, PPLEU has included in
rate base the original cost of plant in service as of December 31, 2004, the end of the future test
year, less the reserve for depreciation at the same point in time. PPLEU Ex. Future 1 (Revised),
Sch. C-2. The Department of Defense (US DOD), however, proposed that only the average
balance of plant in service as of December 31, 2003 and December 31, 2004, reflecting one-half
of the plant additions during 2004, be reflected in rate base. DOD witness Prisco’s entire
statement of his position on this issue is as follows:
Q.
PLEASE EXPLAIN YOUR ADJUSTMENT TO THE
COMPANY’S PROPOSED MEASURES OF VALUE.
A. PPL included in the test year the total of all capital additions
estimated in its future test year budget. I recommend that only the
average or one half of the new additions be allowed. This is based
on the principle that only about half of the additions will be used
and useful for providing service to the test year number of
customers. Therefore, I have eliminated $64,684,000 from the
Company’s measures of value on DOD Exhibit TJP-3.
DOD St. 1, pp. 9-10. This is a rough cut adjustment that does not reflect any knowledge of the
new additions, or at what state of completion they are now. US DOD did mention this
adjustment in its Main Brief, and reflected it in its Table 2 at the end of its Brief. However, it
presented no argument supporting this adjustment, and it filed no Reply Brief to answer
PPLEU’s arguments.
The Company asserts that:
DOD’s proposed adjustment is based upon a misconception of
Pennsylvania ratemaking practices and policies and should be
rejected. Contrary to DOD’s apparent belief, all components of
rates have been adjusted to reflect an end of future test year level
of operations, not a mid-year level of operations. PPLEU has
adjusted rate base, operating revenues and expenses to reflect an
end of future test year level of operations. Consequently, it is
17
entirely appropriate for rate base to reflect an end of future test
year level of plant. PPLEU St. 5-R, pp. 9-10. Indeed, failure to do
so would create a fundamental mismatch between rate base and all
other elements of rates.
PPLEU MB at 18.
The Company further asserts that: “DOD’s adjustment to rate base, based on an
average future test year level of plant, should be rejected as inconsistent with established
principles of Pennsylvania ratemaking.” The ALJ opines that US DOD is not concerned with
rate making policy or matching rate making elements. It is concerned with matching test year
used and useful additions to test year customers. While this approach might have some merit, it
is not well developed on this record. The Company’s statement of the Commission’s ratemaking practice is correct.
The ALJ recommends that the Commission reject this adjustment to the
Company’s claimed rate base.
4.
CAPITALIZED PORTION OF PENSION EXPENSE
Because the ALJ has recommended rejection of the OTS adjustment to the
Company’s pension expense claim, she must also recommend that the Commission reject the
OTS recommendation to deny the Company’s capitalized portion of pension expense.
V.
REVENUES
The revenue increase and the various iterations of both the historic and future test
years calculated to produce the figures are described in the Direct Testimony of Oliver G. Kasper
(Kasper). PPLEU St 6 at 4-8. The schedules showing the steps are found in Exhibit Future-1
(Revised), Schedule D-3 at 1 to 7A.
In its Main Brief, the Company explains that:
18
PPLEU has calculated revenues for the future test year
based upon a forecast of sales to customers. The forecast was
developed using an econometric model and reflects normal
weather conditions. The forecast was then adjusted to reflect the
number of customers projected at the end of the future test year
and the average level of usage per customer at the end of the future
test year. See, PPLEU St. 3, pp. 4-8; PPLEU Ex. Future 1
(Revised), Sch. D-3. To reflect the projected increase in average
usage by customers, PPLEU added $4,850,905 to revenues at
present rates. To reflect changes in the number of customers
PPLEU reduced revenues at present rates by $722,670. PPLEU
Ex. DRW1, p. 5. Total pro forma revenues at present rates are
$523,544,000. PPLEU Ex. Future 1 (Revised), Sch. D-1.
PPLEU MB at 21
The total proposed revenue is $2,946,995,778.00. The total proposed change is
$221,771,697.00. The percentage change is 8.14%. Exh Future -1 (Rev), Sch D-3 at 7A
Three adjustments have been proposed to the Company’s requested revenues by
the parties. OTS and OCA propose to calculate and annualize late payment revenues differently.
US DOD seeks to increase the revenues at present rates by $2,395,000.00 to reflect the
difference between actual unbilled revenues at the end of 2003 and projected unbilled revenues
at the end of 2004. OTS proposes a weatherization adjustment to PPLEU’s projected average
usage for residential heating customers.
1.
UNBILLED REVENUES
PPLEU’s Adjustments to Operating Revenue for the year ended December 31,
2004 are reflected at Schedule D-3 of Exhibit Future-1 (Revised), Lines 12 & 13. The Company
excludes $2,395,000.00 of unbilled revenues from the future test year. US DOD’s witness Prisco
simply reinstates it. The sum total of his testimony to support this adjustment is set forth below:
The Company eliminated $2,395,000 of unbilled revenues from the
test year. I believe this is not appropriate since the Company is
using a future test period which utilizes estimated budget figures to
19
determine revenues, expenses, plant additions. The Company’s
estimate of unbilled revenues should be as accurate as any of the
other estimates used in the future test period and should be
included in revenues. The elimination of unbilled revenues creates
a mismatch between revenues and expenses for the accounting
period. PPL reports unbilled revenues through the end of an
accounting period for financial and tax purposes. They are
eliminated for regulatory purposes only. DOD Exhibit TJP-4
reverses the revenue effect of the Company’s adjustment to
unbilled revenues.
US DOD St 1 at 8; Exh TJP-4. In is Brief, US DOD argues that some jurisdictions make this
adjustment as a matter of course, but acknowledges that Pennsylvania is not one of those
jurisdictions. US DOD MB at 5
The Company responds that this adjustment is in error, and would create double
counting of some revenues:
Differences in unbilled revenues at the end of the historic
test year and at the end of the future test year are caused primarily
by changes in the number of customers and differences in weather
conditions. Tr. 495. PPLEU already reflects these differences in
its forecast of future test year revenues. Specifically, PPLEU
budgets revenue based upon normal weather conditions and for
ratemaking purposes annualizes test year revenues from customers
to account for changes to the number of customers in the test year
and changes in customers’ usage for the full twelve months of the
test year. DOD’s proposed adjustment to unbilled revenues
therefore would improperly duplicate PPLEU’s annualization and
normalization adjustments. PPLEU St. 5-R, pp. 13-14.
PPLEU MB at 26-27
PPLEU also cites to a previous Pennsylvania case holding that the revenues for
rate making revenues should not be adjusted to reflect unbilled revenues. Pa. P.U.C. v. Dauphin
Consolidated Water Supply Co., 14 PUR 4th, 198, 215-16 (1976) (Dauphin). In this case,
Dauphin in its bookkeeping procedure adjusts its books to an accrual basis for revenues earned in
the past year. It returned its revenues to a billed basis for rate case presentation.
20
The PUC found:
The procedure requires the booking of earned but unbilled
revenues at the end of the year and the reversal of billings made at
the beginning of the year for earned revenues at the end of the
previous year. This is a normal and correct accounting adjustment.
However, respondent, like all utilities with few exceptions,
presented its rate case revenues on an “as-billed” basis, which
method, has been consistently followed in its previous rate cases.
When this consistency of practice is followed, there is little
difference in the results, since either twelve months of billed or
twelve months of earned revenues are representative.
Id. at 215. The Company does not claim that it keeps its books as is done in Dauphin, but does
assert that its annualization and normalization of revenues to project test year revenues removes
the need for an unbilled revenues adjustment.
The ALJ chooses to rely on the Company’s arguments, and recommends that the
Commission reject US DOD’s proposed adjustment to delete $2,395,000.00 in unbilled revenues
from the Company’s revenues claim.
2.
LATE PAYMENT FEES
OTS witness Gruber states that late payment fees refer to the revenue received by
the Company for late fees from customers who do not pay their bill by the due date. The
Company includes $6,000,000 in Revenues in Total Revenue per budget and T & D Revenue per
Budget and in Pro Forma at Present rates. Exh Future 1 (Rev), Sch. D-3, line 8.
According to OTS, as shown in OTS Exhibit No. 5, Schedule 1 (PPLEU
Response to OTS Interrogatory), the Company states that it based its claim for late payment
revenue on an average of the last five years. An examination of the Company’s response shows
that it understated these revenues by $336,000 in its exhibits submitted for the case. In Rebuttal,
the Company agreed that it had erroneously rounded the figure down to $6,000,000.00 and that it
should have used the amount of $6,336,000 and that it would now and henceforward use the
21
unrounded figure. PPLEU St 2-R at 16. However, this figure did not make it into Exhibit Future
1 (Rev), which still uses the figure of $6,000,000.00
OTS further argues that by using a simple five year average, the Company has
understated the amount of late payment revenue:
The Company’s use of an average level of late payment fees will
understate the late payment revenue. A simple average does not
take into account the Company’s increase in the overall level of
revenue. By using a simple five year average the Company does
not take into account that customers who do not pay their bill at the
existing rates will, in all likelihood, not pay them at the new higher
rates. Therefore, use of a simple average would understate late
payment revenue if, for no other reason, the customers who do not
pay their bill will have a higher bill they will not be paying.
OTS St 5 at 18.
Accordingly, for use in determining the future test year late payment revenue,
OTS developed a three-year historical average of the percentage of overall revenue represented
by the late payment revenue for the last three years (a weighted average percentage), which
produced a factor of 0.2818%. OTS then applied this factor to pro forma revenue (including the
$336,000) at present rates and concludes that pro forma revenues should be increased by
$1,129,000.00. OTS St 5 at 18-19; Sch 5, at 2. OTS witness Gruber recommends that “The final
late payment revenue would be determined by applying the percentage of late payment revenue
of 0.2818% (OTS Exhibit 5, Schedule 2, Line 7, Column 4), as it is shown in my exhibit, to the
total allowable revenue found by the Commission.” OTS St. 5 at 19
OCA witness Morgan, after reviewing the Company response to OTS correcting
its amount of late payment revenues by $336,000.00, and reviewing the OTS adjustment
applying a weighted average percentage factor, adopted the figure of $330,000.00 after applying
the Pennsylvania jurisdiction allocation factor, and the OTS method, and revised his schedules to
show an increase to present revenues of $1,080,000.00. OTS St 1-S at 4; Sched LKM-19S.
Morgan stated that “The 3-year average ratio has been found reasonable for estimating
22
uncollectibles. Consistent with that finding, I believe the 3-year average ratio is appropriate for
use in this adjustment.” OCA St 1-S at 4. The Company does not challenge this.
The Company blends together the OTS and OCA rationale for this adjustment,
and ends by saying that it agrees with OCA’s logic, and argues that the same method should be
applied to uncollectibles expense, and that the two adjustments would then cancel each other out.
OCA bases its rationale in part on Commission rulings on uncollectible expense. OCA MB at21;
OCA St 1 at 4.
If the ALJ understands the Company’s Brief, its uncollectible accounts expense is
already calculated by applying the historical relationship of uncollectible accounts to revenues
(0.655%) to its proposed increase in rates. PPLEU MB at 28. The Company contends that the
amount of uncollectible accounts expense which would result from the rate increase would be an
amount that would offset the late payment adjustment proposed by OTS and OCA. The
Company ends by saying that the ALJ and the Commission should either make adjustments on
both late payment revenues and uncollectibles, or make it on neither. PPLEU MB at 27-28;
PPLEU RB at 11-12. The ALJ opines that the Commission is not required to make any
adjustment that the Company did not itself make. The Company received ample notice of the
OTS adjustment when OTS filed its direct testimony, and the Company could easily have
“grossed up” its uncollectibles expense in Rebuttal testimony if it thought it appropriate to do so.
In their Reply Briefs, both OTS and OCA discount this argument. OCA asserts
that the Company’s “logic” does not apply because there are many aspects of the amount of
uncollectibles expense that are in management’s control, whereas late payment revenue accrues
when the payment is late whether it is in full or not. OCA RB at 10-11. OTS argues that it has
exposed flaws in the Company’s methodology for calculating late payment revenue, and has
presented a superior methodology, and that the Company’s linking of this revenue adjustment to
an expense adjustment is fallacious. OTS RB at 12-13
The ALJ might be able to agree with the Company’s argument under other
circumstances, but she is not willing to accept the Company’s calculation of the uncollectibles
23
increase as baldly stated in its Brief, or the necessity of mirroring these adjustments. The
Company’s arguments and figures on uncollectibles expense have not been presented in
litigation to the other parties. The ALJ has only one adjustment before her here, not two, and she
will rule on that one, late payment revenue, without consideration of uncollectibles expense.
The ALJ believes that she should correctly follow the Commission’s guidance,
and OCA persuasively asserts that the guidance favors the historical weighted average
adjustment. Both OTS and OCA argue persuasively that the size of the revenue adjustment
should be related to the size of the increase. Therefore, the ALJ recommends that the
Commission adopt the OTS adjustment because the underlying calculation is clearly set forth,
and adjust it by the Pennsylvania jurisdictional allocation factor if necessary. The effect of this
adjustment is to increase future test year revenues by at least $1,129,000.002. OTS Exh 5 at 2.
OCA’s adjustment would increase revenue by $1,080,000.00.
3.
SALES FORECAST
PPLEU’s sales forecast is comprised of two separate elements: the number of
customers by class at the end of the future test year, Ex. DRW1, at 5-6; PPLEU St. 3, at 6; and
the projected changes in average annual usage by customers, PPLEU Ex. DRW1 at 3-4. PPLEU
MB at 21.
The change in the average level of usage by customers was
developed using an econometric model, a [proprietary] software
program, METRIX ND, which was developed by RER, Inc. OTS
Ex. 3, Sch. 4, p. 1. OTS objected to PPLEU’s projection of the
average usage for residential heating customers on several
grounds...
PPLEU MB at 22. OTS is the only party that presented an adjustment to this usage. No issue
was raised by any party with regard to the projected number of customers.
2
In its Reply Brief, OTS asserts that applying its method and factor to its proposed
revenues in this case, the increase in revenues would $1,240,000.00. OTS RB at 13
24
OTS has also developed its own forecast of customer usage based on a standard
weather normalization analysis similar to those frequently used in gas base rate cases. PPLEU
criticizes the OTS adjustment on that basis, among others. OTS argues that its correction of
PPLEU’s forecasted usage results in an adjustment of an additional $3,065,000 to the
Company’s claimed revenue. OTS Exh 3, Sched 8 (Rev)
OTS finds PPLEU’s usage projection unacceptable because: the Company uses
weather data provided by a private company that is not readily available to other parties, and
does not use the publicly available data from the National Oceanic and Atmospheric
Administration (NOAA); the private company makes corrections to the NOAA data; the
Company uses only 20 years of data, not the standard 30 years; and, the Company uses an
econometric model that is not accessible to OTS and the other parties. OTS argues that:
“The Company has not shown that a variation from widely accepted principles is appropriate in
this proceeding. Its recommendations are based on its own forecasts, models and projections
without the underlying data used in its methodology,” and thus has not met its burden of proof.
The Company responds that its weather data originates at airport weather stations
operated either by NOAA or the FAA; hourly data is sent to a central NOAA facility near
Washington D.C.; Meteorlogix, a service used by the Company, receives the data hourly from
NOAA, and PPLEU receives that data every day by means of a file transfer protocol.
Meteorlogix merely receives NOAA data, excludes erroneous data, and includes estimates for
any missing data. PPLEU St 3-R at 6-7. The Company argues “Thus, under any realistic
evaluation, meteorological data used by PPLEU in its econometric model is provided by NOAA,
albeit indirectly.” PPLEU MB at 23. The ALJ agrees.
OTS argues that PPLEU receives data that has been altered by Meteorlogix which
initially has the discretion to decide what data is erroneous, and what data to use to estimate
missing data. OTS has testified that this data is different from the NOAA data that it uses. OTS
St 3 at 8.
25
OTS does not argue that it attempted to review the Meteorlogix data, and was
refused access. OTS does quarrel with the Company on several other grounds. First it says that
the Company points to an error it made in its original direct testimony, which OTS corrected in
its Surrebuttal testimony, and argues that the error should be forgotten. Second it contends that
the PPLEU comparison of six months of actual results to its own forecast shows that its forecast
is lacking, and that its use of OTS data for a similar comparison mischaracterizes the data as a
forecast when it is not, and uses old data which has now been corrected.
The Company further responds that it uses 20 years of data because, for weather
normalization to be accurate, it is necessary to use revenue month, not calendar month data to
match usage with temperatures. The Company does not have 30 years of revenue month data,
but it does have 20 years, so it uses 20 years. The alternative would be to mismatch temperatures
with usage data, which the Company asserts is clearly not appropriate. PPLEU MB at 23
The Company also responds that OTS asked it to provide a working copy of its
econometric model in Excel, but that the model does not exist in Excel, which it fully explained
to OTS. Further, the model is quite large, and is installed on a server, and requires access to
PPLEU’s network to operate. The Company claims that OTS did not attempt to follow up on
access to the econometric model after finding out that it does not exist in Excel. PPLEU MB at
22
OTS’s main argument is that the Company has not met its burden of proof
because it uses weather data and an econometric model that is not available to the parties, and is
not a part of the record. OTS argues that if it cannot examine and test the assumptions and data
inputs to the METRIX ND model, its results cannot be used as evidence because they are not
supported by evidence of record. OTS also argues that the Company’s projection is
unacceptable because it uses a 20-year period as a basis for its projections, rather than the
generally-accepted 30-year period.
Regarding the accessibility of METRIX ND, the conduct of both parties is
disappointing. The ALJ opines that OTS should have been afforded an opportunity to test the
26
use of this model somehow. If the issue is that the model is proprietary, then a Protective Order
is available under the rules. 52 Pa. Code §§5.362, 5.423. If the issue is that the test cannot take
place on Commission facilities, then staff should have been afforded the opportunity to use the
server and have access to the PPL network. However, it appears that the parties stopped talking
after the revelation that METRIX ND does not reside in Excel; it appears that there were no
further negotiations. OTS did not file a Motion to Compel at that time, or a Motion to Strike
relevant testimony later. Neither the Company nor OTS sought a Protective Order. Things
remain at a standstill yet, allowing OTS to make its failure to meet burden of proof argument.
The Company has obviously spent some time and money in developing the tools
(METRIX ND and 20 years of data) with which it makes sales projections. It is obviously
entitled to do so, and to use these tools to make its projections, which it feels are superior for its
purposes. The ALJ opines that particularly in this new era of competition, the Company will
want to be as accurate as possible in this area so it can plan accordingly, and that the
Commission should not tell it what projection tools to use. If the Company did not use these
tools for presentation of its sales forecast in this case, but merely substituted the OTS
methodology, then the Commission would not know how PPLEU goes about making its
projections and reaching its decisions.
The ALJ recommends that the Commission direct OTS and PPLEU to work out a
solution to this problem before PPLEU files its next rate increase request. While the ALJ
recognizes some merit in the OTS ‘failure to meet burden of proof’ argument, she also opines
that OTS could have pursued access to the data more vigorously, and could have moved to
prohibit Company testimony on this subject from coming into the record if it really thought the
testimony was not probative.
Moreover, the ALJ opines that the testimony and exhibits presented by the
Company on this issue are sufficiently probative to support its projections. It would be far better
if OTS could have had access to the underlying tools, and had been able to probe the methods
used by the Company, but the ALJ will not dismiss PPLEU’S sales projection results solely on
that basis.
27
Continuing with the Company’s responses to OTS, PPLEU asserts that it uses a
20-year period rather than a 30-year period because, beginning in 1985, it matched its usage
month to a revenue month, and thus got more accurate results. It has 20-years worth of this data.
The Company states that using a calendar month with a revenue month mismatches data:
The forecast PPLEU produces is a forecast of revenuemonth sales. In OTS Exhibit No. 3, Schedule 7, Mr. Kubas
attempts to normalize revenue-month sales using calendar-month
weather data. Any comparison of monthly sales and weather must
be done on the same basis. Bills are rendered to customers
throughout the month and, therefore, revenue-month sales will not
directly correspond to calendar-month HDDs [heating degree days]
and Cooling Degree Days (CDDs). For example, if one makes the
simplifying assumption that customers are billed the same time
every month, then a customer who is billed on the 15th day of each
month will have half of his usage in the current month and half of
his usage in the prior month. In order to make a comparison of
revenue-month sales and weather, the weather data must be
adjusted to show the HDDs applicable to the usage in the current
month, and the HDDs applicable to the usage in the prior month.
In reality, customer meter reads are not the same time every
month, and the number of billing days will vary. The HDDs and
CDDs for all 20 billing controls must be calculated on a daily basis
in order to place the sales and weather data on the same revenuemonth basis. As explained in the response to OTS Interrogatory
OTS-RE-6, the revenue-month values are calculated in PPLEU’s
forecast model based on meter reading schedules.
Prior to 1985, PPLEU had used calendar-month HDDs and
CDDs. PPLEU recognized this inherent weakness in using
calendar-month HDDs and CDDs and began using revenue-month
HDDs and CDDs, based on daily degree days.
PPLEU ST 3-R at 3-4
The ALJ finds the Company’s argument persuasive that using calendar months
with usage months mismatches data, and that PPLEU’s method of placing sales and weather on
the same revenue month basis will produce more accurate projection results. The ALJ rejects
OTS’s characterization of this data as “massaged” data. The Company itself has collected the
28
data for revenue months for 20 years. OTS regards the Meteorlogix data as “massaged” data
because the service corrects what it considers to be erroneous data and inserts estimates for
missing data. I do not consider this massaging data, which generally means manipulating data to
produce a different biased result as compared to the result from the data in its raw state. It is not
even known if the Company has been using the service for 20 years.
OTS also asserts that the standard for weatherization data is 30 years for normal
degree days:
The data is [compiled] by the NOAA and it defines “normal”
levels of heating degree-days according to the following definition:
Methodology: Normals have been defined as the
arithmetic mean of a climatological element computed over a
long time period. International agreements eventually led to
the decision that the appropriate time period would be three
consecutive decades. Climatography of the United States No.
81, Pennsylvania January 1992.
OTS St 3 at 4. OTS witness Kubas goes on to state the value of a 30-year horizon:
First, it is my opinion that 30 years encompasses a time period
sufficient enough to “smooth” short term aberrations in weather
patterns. Second, it is consistent with the long-standing 30-year
normal that NOAA and the Commission accept for determining
normalized HDDs.
OTS St 3 at 9. Because the Company does not use this basic generally-accepted data as a
starting point, OTS regards the Company’s entire analysis as wrong.
The ALJ opines that a more finely tuned, individually tailored projection which
matches revenue months to usage months will be more effective than a one-method-fits-all
projection. The latter is acceptable if no other method is available, but in this case there is a
more accurate method. Moreover, the OTS methodology was designed for use with the natural
gas utility industry which has only winter peaking characteristics for the majority of its heating
29
customers, whereas the electric utilities in Pennsylvania, and in particular PPLEU, have marked
summer peaking characteristics for both its heating and non-heating customers.
The Company also points out that
... PJM has established a standard summer peak demand process
that incorporates a 20-year rolling average weather parameter
(PJM Manual 19: Load Data Systems, Section 4). PPLEU also
provides PJM with monthly sales forecasts. In order to be
consistent with the PJM requirements, PPLEU elected to use a 20year rolling average in its process of obtaining sales on a normalweather basis.
PPLEU St 3-R at 7. OTS witness Kubas responds that PJM can set whatever standards that are
useful to it, but that the Commission is not bound to use them for ratemaking purposes. While
this is true, it is also true that the Commission should be cognizant of new standards being
developed in the competition era.
The Company criticizes the OTS entire approach as designed for use with natural
gas utilities, and asserts that it is not appropriate for electric utilities in general and itself in
particular. Natural gas heating sales always peak in the coldest months of the winter. Witness
Woodward shows that the Company has had and projects almost equal peaks in summer and
winter. PPLEU Exh DRW1, page 2 of 6. The Company disagrees with the OTS selection of
October as the base load month because it includes heating use; disagrees with inclusion of May
in the winter months; opines that OTS does not acknowledge the use of air-conditioning in the
summer months; and, does not acknowledge the greater use of lighting in the winter months and
over the winter holidays. As a result, the Company argues,
... the OTS projection of average annual usage for
residential heating customers was based upon a traditional weather
normalization calculation that considers only base load, usage per
degree day and comparisons of actual degree days to average
degree days. OTS used this procedure apparently based upon its
witness’ experience in gas utility rate cases, in which heating
customers’ usage variations depend almost entirely upon variations
30
in temperatures. He has not testified previously in electric utility
rate cases. Tr. 552.
PPLEU MB at 24. The Company continues with its analysis as follows:
(2)
Data used in the OTS’ weather normalization
include only the number of customers, actual load, base load,
actual and average heating degree days. OTS Ex. 3, Sch. 7. There
are no data in the OTS normalization that are capable of capturing
the fact that electric distribution companies, in contrast to natural
gas companies, experience substantial air conditioning load during
the warm summer months. PPLEU St. 3-R, p. 4.
(3)
OTS’ projection does not properly determine nonweather sensitive “base load.” In weather normalization
procedures, “base load” is load that is not affected by temperature
variation. Base load is used to identify the portion of a heating
customer’s load that is not heat-sensitive, and therefore, is not
adjusted based on heating degree days. OTS employed October
load as its “base load,” that is, non-temperature sensitive load.
This is not appropriate because October contains substantial
heating usage. Specifically, under NOAA published “normal”
degree day data, October, on average, experiences 395 heating
degree days, which is approximately 7% of the normal level of
annual degree days of 5,833, as published by NOAA. OTS Ex. 3,
Sch. 7. Consequently, OTS’ “base load” contains significant heatsensitive load and therefore is not reliable.
(4)
OTS’ projection ignores the fact that lighting
requirements are higher during the winter due to reduced hours of
daylight. Further, holiday lighting adds additional load. Summer
usage is affected by reduced lighting needs, more outdoor activities
and vacations. PPLEU St. 3-R, p. 5.
PPLEU MB at 24-25.
OTS Witness Kubas in his summary exhibit projects only heating sales, and
makes no similar projection for cooling sales; he assesses heating degree days (HDDs), but not
cooling degree days (CDDs).
31
The Commission is left with a sales revenue projection that OTS argues is not
adequately supported on the record, and another sales revenue projection which the Company
has persuasively argued is seriously flawed.
The ALJ recommends that the Commission rely on PPLEU’s sales projection.
The ALJ opines that, on balance, there is sufficient evidence on the record to support its results,
e.g., PPLEU Exh DRW-1 at 1-6, and that the OTS projections are not sufficiently suited to the
electric industry to supercede them in usefulness.
4.
DISTRIBUTION SYSTEM IMPROVEMENT SERVICE CHARGE
The proposed new Distribution System Improvement Service Charge (DSIC) is
presented in the Testimony of PPLEU witness Douglas A. Krall. PPLEU Sts 4 at 35-39 and 4-R
at 2-18. The DSIC is set forth in the proposed new Tariff, Supplement No. 38, Electric
Pa.P.U.C. No. 201 at Page Nos. 19Z.2, 19Z.3 and 19Z.4
Every intervening or complaining party that has taken a position on the DSIC is
against it, including most notably OTS, OCA, OSBA, and PPLICA each of whom opposed the
DSIC in their Brief. The common themes of these objectors are: the DSIC is illegal under the
Public Utility Code (Code), specifically under 1307 (a) (regarding a sliding scale of rates) read in
conjunction with 1307 (g) (regarding DSICs for water utilities); that such a surcharge would
constitute impermissible single issue rate making; that it is improperly designed because it
collects revenues on a kwh cents per hour basis rather than on a demand basis; that it guarantees
continual rate increases whether they are needed or not; that it does not provide for sufficient
Commission overview; and, that it is contrary to Commonwealth Court precedent and
unsupported by recent Commission precedent.
In requesting its DSIC, PPLEU has quite clearly modeled its automatic
adjustment clause on a DSIC and a CSIC previously approved by the Commission for
Pennsylvania American Water Company, which over recent years has acquired three wastewater
systems. Re Pennsylvania-American Water Company, 86 PaPUC 415 (1996) (DSIC order); Pa.
32
P. U. C., et al., v. Pennsylvania American Water Company, Docket No. R-00027982, Order
entered November 7, 2003 (CSIC order). It incorporates most of the features of those clauses.
OCA provides an excellent summary of this adjustment, which I have
incorporated in the following discussion:
In its filing, PPL proposes implementation of a DSIC which
would allow the Company to recover (between base rate cases)
capital-related costs on certain capital investments in distribution
facilities. PPL St. 4 at 35. Specifically, the fixed costs recovered
through the DSIC would include depreciation, a return on
investment and income taxes associated with new projects placed
in service each year. OCA St. 2 at 4. The Company proposes
three categories of distribution investments which would be
eligible for cost recovery under the DSIC: 1) replacements for
existing facilities that have worn out, are in deteriorated condition,
or need to be upgraded to meet new regulations, 2) unreimbursed
costs related to capital projects to relocate Company facilities due
to highway relocations, and 3) security improvements that are
recommended by a Federal or State governmental entity with
appropriate jurisdiction over security matters. PPL St. 4 at 35-36;
OCA St. 2 at 4.
OCA MB at 187
The Company states:
“For most categories of plant it proposes to install, PPLEU
has specifically identified that plant by reference to distribution
plant accounts as set forth in the Uniform System of Accounts
applicable to electric utilities. These accounts are as follows:

Poles (Account 364), oil circuit reclosures (Account 365),
underground cable (Account 367) and underground services
(Account 369) installed as in kind replacements;

Area supply substation equipment (Account 362) replacements
due to deterioration, failure, or obsolescence to maintain
reliability;

Distribution line circuit capital replacements to maintain
reliability”
33
The other categories include:

Unreimbursed costs related to capital projects that relocate
PPLEU facilities due to highway construction; and

Unreimbursed costs related to facilities relocation projects due
to highway relocation work

Security improvements
PPLEU MB at 123-124; Tariff Page 19Z.2
Under the Company’s proposal, the DSIC would be calculated annually and
charged monthly. Proposed Tariff Pages 19Z.2-19Z.4.
The Company would initially accumulate DSIC-eligible
investments from January 1, 2005 to December 31, 2005. PPL St.
4 at 37. The Company will then calculate the DSIC charge and the
initial DSIC would first appear on bills rendered on January 1,
2006. Id. This initial charge under the DSIC Rider would become
effective on January 1, 2006 and would include eligible investment
for the period January 1, 2005 through November 30, 2005. OCA
St. 2 at 4. The charge would be increased each subsequent January
1st to include any new investment in the prior twelve months ended
November 30th, while still retaining the plant from the previous
year, and so on each year until a rate case is filed. Id. at 4-5.
OCA MB at 187. In other words, it would be cumulative. The clause would be limited to, or
capped at, no more than five percent of PPLEU’s distribution charges between rate cases.
The
DSIC would be reset to zero at the time of each rate case. The Company has proposed that the
DSIC be subject to annual reconciliation so that any undercollection of eligible costs would be
recouped by the Company or any overcollection would be refunded to ratepayers. PPL St. 4 at
38; Proposed Tariff Pages 19Z.3, 19Z.4
34
By tying the eligibility of plant additions to specific distribution plant
replacements in these accounts, PPLEU has minimized discretion and ambiguity because these
accounts are clear and well-defined under the Uniform System of Accounts.
OCA further relates that “PPL analyzed a typical year’s worth of property
additions and estimated that initial implementation of a DSIC would result in about $3.3 million
in additional revenues that would have to be collected. Until there is a base rate proceeding,
DSIC-eligible property would be eligible again in the next year, as would additional eligible
property installed.” PPLEU St 4 at 20, 38; OCA MB at 1188
As noted above, OCA opposes the DSIC.
A.
Need for the DSIC
PPLEU asserts that the proposed DSIC is in the public interest and that it needs
the proposed rate because:
PPLEU needs a DSIC in order to facilitate the substantial
investments that will be necessary to replace its existing, aging
distribution system infrastructure. The aging infrastructure results
primarily from the substantial high growth era in the 1960s, 1970s
and 1980s, when PPLEU’s distribution system was greatly
expanded. PPLEU St. 4, p. 35. These additions, some of which
are approaching 50 years of age, are nearing the end of their useful
lives.
The aging nature of PPLEU’s distribution system can be
illustrated by reference to poles. PPLEU installed 106,050 poles in
the 1950s. With economic growth and increased use of electricity
in PPLEU’s service area, however, that number grew to 184,104
during the 1960s and rose to 234,046 during the 1970s. As the
number of poles installed during the 1960s and 1970s age, the
number of poles that PPLEU must replace will grow substantially.
PPLEU St. 4-R, p. 14.
Analysis of other plant accounts shows similar results.
PPLEU’s distribution system is part of this nation’s aging
infrastructure, which includes highways, bridges, water systems
35
and sewer systems. PPLEU has proposed the DSIC as a proactive
measure to anticipate the need for significant capital investments to
maintain the distribution system in a condition that will enable
PPLEU to continue to provide reliable service.
PPLEU MB at 121-122
In the DSIC Order, the Commission focused on the Company’s need to replace
aging infrastructure to be able to come into compliance with the evolving requirements imposed
by the Safe Water Drinking Act, and to be able to implement solutions to regional water supply
problems. 86 PaPUC at 417. This clause also included a 5% cap on the amount otherwise billed
to customers, reconciliation, and other features found in PPL’s proposal.
In the CSIC Order, the Commission relied on the Company’s need for capital
investment to avoid hydraulic overloading, a condition that is created when the amount of waste
water exceeds the capacity of the system to carry it. At that point, the only choice is to divert the
flow away from facilities that may other wise be damaged, which may then cause contamination
of surface and groundwater supplies. The Pennsylvania Clean Streams Law imposes conditions
and planning obligations on waste water service providers to control flow and avoid over
flow and infiltration of other water sources. CSIC Order, Slip Opinion at 5-6
One issue to be resolved is whether PPLEU has demonstrated a need to repair and
replace its facilities equivalent to the need facing the water and waste water utilities in the cited
cases. The ALJ opines that it has not. PPLEU is deservedly proud of its service and safety
records, and came nowhere near averring that it is approaching serious reliability problems, or
that its facilities are so aged that they are near collapse, and thus are a threat to the public, its
customer or its workers. The waste water utility in the CSIC Order was apparently nearing
overflow problems, or felt a need to prevent it.
The Company contends that its need to provide security would be a requirement
similar to the statutory obligations on Pennsylvania American relating to water and waste water
services. There is certainly no statutory or regulatory requirement that the Company has cited
36
mandating certain actions and investments to create and maintain greater security. It is not clear
whether the Company considers such requirements to be conditions precedent to claiming
security costs in the clause.
The ALJ does not agree with those parties that argue that security concerns relate
only to transmission facilities, and thus should not be a cost to PPLEU. If that logic is carried far
enough, then only generation facilities would need security protection. One has only to
remember the effect of the blackout spreading from Ohio to other states, or closer to this case,
the damage done to the Company’s system by Hurricane Isabel. There was damage not only to
transmission facilities, but also to a great number of distribution facilities3.
The next issue to be resolved is whether the Commission requires really dire
circumstances before it will consider or grant an automatic adjustment clause for other utilities,
specifically, electric utilities. PPLEU here has made a really good argument for avoiding
regulatory lag, a problem inherent in the PUC system as it now exists. However, if PPLEU’s
request is granted, why not grant an automatic adjustment clause to every utility that asks?
Where would the Commission draw the line, if it wanted to draw a line?
In 1984, the Legislature drew a line, and required natural gas utilities with
revenues over $40 million to establish gas cost rate clauses under Section 1307(f) of the Code.
66 Pa.C.S §1307(f). More recently, in 1996, the Legislature created an automatic adjustment
method allowing water utilities to recover “costs related to distribution system improvement
projects’, without differentiating among them. 66 Pa.C.S §1307(g). However, according to
testimony presented in this case, some in the Legislature are not in favor of more such clauses.
Finally, there is the issue as to whether the PUC should create another such clause
at all. OTS, arguing against the Company’s proposal to be allowed an automatic adjustment
clause, quoted testimony on behalf of the Northeast Delegation in support of its position:
3
The ALJ opines and speculates that many security precautions will require electro-mechanical
solutions within the system (e.g., remote control switches, modern reclosers) rather than extraneous guard booths,
for example.
37
Obviously, if the Legislature intended to give the
Commission the authority to grant a DSIC to electric distribution
utilities it would have specifically identified the industry in this
section or, alternatively, created an additional section specifying
the applicability of this section to the electric industry. DSIC
surcharges were clearly intended to pertain only to the water
industry. This is further supported by the testimony offered on
behalf of the Chair of the Northeast Delegation, the Honorable
Phyllis Mundy. Also sponsoring this testimony are delegation
members the Honorable Kevin Blaum, the Honorable Todd
Eachus, the Honorable Jim Wansacz, the Honorable Tom Tigue
and the Honorable Bob Belfanti. The testimony reads, in part:
…[a]s State Legislators, [we] stress that it was not the
intent of the Legislature in 1996 to give broad authority to
the PUC to authorize a DSIC for all utilities but rather limit
the DSIC to water companies.
Consistent with this is the fact that the House of
Representatives has twice rejected the legislation that would
impose a DSIC for gas companies. Not only do we believe
that a DSIC approved only by the PUC is unlawful, we think
it is bad public policy.
(Emphasis added). Transcript, p.254.
This testimony indicates the position of the above
mentioned representatives and is bolstered by the fact that the full
House of Representatives has refused, on two occasions, to extend
the DSIC to gas utilities. This clearly demonstrates that if the
legislature intended for the DSIC provision to extend beyond water
utilities, it would have stated so.
OTS MB at 63-64
38
B.
Authority for a DSIC
The Company relies on an interpretation of Section 1307(a) which it shares with
the Commission, and cites the Pennsylvania Supreme Court decision in Elite Limo to support its
statutory interpretation. It also relies on the DSIC Order and the CSIC Order, and other
Commission and Court decisions. Section 1307 (a) provides:
General rule. – Any public utility, except common carriers and
those natural gas distributors with gross intrastate annual operating
revenues in excess of $40,000,000 with respect to the gas cost of
such natural gas distributors, may establish a sliding scale of
rates or other method for the automatic adjustment of the
rates of the public utility as shall provide a just and reasonable
return on the rate base of such public utility, to be determined
upon such equitable or reasonable basis as shall provide such
fair return. A tariff showing the scale of rates under such
arrangement shall first be filed with the commission, and such
tariff, and each rate set out therein, approved by it. The
commission may revoke its approval at any time and fix other rates
for any such public utility if, after notice and hearing, the
commission finds the existing rates unjust or unreasonable.
(Emphasis added in Brief.)
66 Pa.C.S §1307(a)
Section 1307(g) provides:
(g) Recovery of costs related to distribution system
improvement projects designed to enhance water quality, fire
protection reliability and long-term system viability.- Water
utilities may file tariffs establishing a sliding scale of rates or other
method for the automatic adjustment of the rates of the water
utility as shall provide for recovery of the fixed costs (depreciation
and pretax return) of certain distribution system improvement
projects, as approved by the commission, which are completed and
placed in service between base rate proceedings. The commission,
by regulation or order, shall prescribe the specific procedures to be
followed in establishing the sliding scale or other automatic
adjustment method.
39
66 Pa. C.S.A. §1307(g).
Section 1307(b) allows the Commission to make a sliding scale of rates
mandatory. Section 1307(c) allows an automatic adjustment clause called the fuel cost
adjustment to recover the cost of fossil fuel delivered at the generating site. Section 1307(d)
provides for audits of fuel cost adjustment clauses. Section 1307(e) provides for automatic
adjustment reports and proceedings. Section 1307(f) requires that natural gas utilities with more
that $40 million in revenues file a gas cost rate. Section 1307(g) allows the creation of a DSIC
by water utilities.
OTS argues that:
Section 1307 of the Public Utility Code authorizes sliding
scale of rates and adjustments. 66 Pa. C.S.A. §1307. There is no
statutory provision allowing electric distribution companies to
establish the type of surcharge the Company is requesting. Any
argument offering subsection (a) as authority for implementation
of this charge requires that the fact-finder completely ignore the
provisions of 66 Pa. C.S.A. §1307(g). Section (a) states the
general rule in the establishment of a sliding scale of rates. Section
(g) specifically deals with distribution system improvement
charges. If, as the Company suggests, §1307(a) is the controlling
provision with respect to establishing a DSIC, then there would be
no reason for the Legislature to enact §1307(g). A careful reading
of the two provisions of the Code will reveal the error in the
Company’s premise and demonstrate that the Legislature did not
intend for §1307(a) to be all-inclusive as the Company suggests.
The appropriate section of the Code controlling the implementation
of a DSIC is §1307(g) as provided in its language:
Obviously, if the Legislature intended to give the
Commission the authority to grant a DSIC to electric
distribution utilities it would have specifically identified the
industry in this section or, alternatively, created an
additional section specifying the applicability of this
section to the electric industry. DSIC surcharges were
clearly intended to pertain only to the water industry.
40
OTS MB at 62-63. OCA agrees with this argument, and sets its position forth at some length in
its Briefs.
The Company argues that:
Section 1307(a) clearly grants the Commission broad authority to
fashion rate adjustment mechanisms subject to the overarching
requirement that any such mechanism must “provide a just and
reasonable return on the rate base . . . to be determined upon such
equitable or reasonable basis as shall provide such fair return.”
Nothing in this language is ambiguous. And, nothing in Section
1307(a) limits the kinds of costs that may be recovered there under
or withholds from the Commission authority to fashion a
mechanism to recover the fixed costs of utility plant. To the
contrary, the operative language specifically references both
“return” and “rate base,” as PPLEU has proposed to reflect in the
DSIC.
PPLEU MB at 113
The Company also argues that a recent ruling of the Pennsylvania Supreme Court,
at Elite Industries, Inc. v. Pa. P.U.C., 832 A.2d 428, 431 (Pa. 2003) (Elite), established rules for
interpretation of provisions of the Public Utility Code delineating the Commission’s authority
should be interpreted. This is somewhat of an overstatement. The Pennsylvania Supreme Court
applied the rules of statutory construction to the disputed provision of the Public Utility Code, 66
Pa.C.S §1103 (a), brought before it. The same rules can be applied here. Section 1921 of the
Statutory Construction Act, 1 Pa.C.S §1921 provides that:
§1921. Legislative intent controls
(a) The object of all interpretation and construction of statutes
is to ascertain and effectuate the intention of the General
Assembly. Every statute shall be construed, if possible, to give
effect to all its provisions.
(b) When the words of a statute are clear and free from all
ambiguity, the letter of it is not to be disregarded under the pretext
of pursuing its spirit.
41
(c) When the words of the statute are not explicit, the intention
of the General Assembly may be ascertained by considering,
among other matters:
(1) The occasion and necessity for the statute.
(2) The circumstances under which it is enacted.
(3) The mischief to be remedied.
(4) The object to be attained.
(5) The former law, if any, including other statutes upon the
same or similar subjects.
(6) The consequences of a particular interpretation.
(7) The contemporaneous legislative history.
(8) Legislative and administrative interpretations of such
statute.
1972, Dec. 6, P.L. 1339, No. 290, §3, imd. effective.
In Elite, the Court held that, in the absence of ambiguity, the “plain language” of
the statute must control. The Supreme Court rejected a prior judicial interpretation purporting to
read into Section 1103(a) of the Public Utility Code, 66 Pa.C.S. §1103(a), a requirement that an
applicant for a certificate of public convenience show a public “need” for its services. The
Supreme Court found that the statute’s “plain language,” namely, the disjunctive phrase
“necessary or proper,” did not make “need” an essential prerequisite and, therefore, the
Commission’s authority under Section 1103(a) should not be constrained in the way prior
reviewing courts [and the Commission itself] had held. Elite, 832 A.2d at 431. This ruling is
certainly straightforward in applying Section 1921 as far as it arises in that case. 1 Pa.C.S §1921
However, in the case before the Commission now, the statutory section has eight
(8) subsections, and Section 1921(a) also requires that “Every statute shall be construed, if
possible, to give effect to all its provisions.” The words of the statute are not particularly
ambiguous, but the many legislative enactments have the effect of rendering Section 1307(a)
somewhat ambiguous.
Section 1307(a) started out as a broad grant of authority that “clearly grant[ed] the
Commission broad authority to fashion rate adjustment mechanisms subject to the overarching
42
requirement that any such mechanism must provide a just and reasonable return on the rate base .
. . to be determined upon such equitable or reasonable basis as shall provide such fair return.”
PPLEU MB at 113. However, the Legislature has since passed three substantive amendments,
and three procedural ones, to Section 1307, which makes clear that it has not entirely delegated
the power and authority to fashion such rate mechanisms to the Commission. In fact it appears
that the Legislature has circumscribed the Commission’s jurisdiction in these matters.
In fact, the way that 1307(g) became a part of the Public Utility Code may be
instructive in that regard. The Commission had moved ahead to create a DSIC for Pennsylvania
American, and OCA had appealed the Commission Order. But then, the Legislature intervened
by passing an amendment, Section 1307(g), adding the DSIC for all water utilities, making the
Commission Order and the OCA appeal moot. The Commission is regarded as a creature of the
Legislature: See Duquesne Light Co. v. Barasch, 488 U.S. 299, 313 (1989) (“[T]he Pennsylvania
PUC is essentially an administrative arm of the legislature. . . . ‘The rate-making power is a
legislative power and necessarily implies a range of legislative discretion.’; In PG&W, the
Supreme Court of Pennsylvania also upheld this principle, finding that the Commission exercises
“the regulatory powers of the Commonwealth,” which include a flexible range of judgment that
should not be constrained by judicially-imposed limitations on the Commission’s authority that
are not found in the plain language of the Public Utility Code. However, it is significant that the
Commission’s authority in this area has not been clarified, but the Legislature has made it clear
that it is still ready to act on its powers on this subject.
The ALJ therefore concludes that she should not recommend that the Commission
proceed to create a DSIC for PPLEU without having legislative input.
C.
Additional Arguments
There are additional arguments which may be of some interest to the
Commission. For instance, OTS, OCA and PPLICA contend that this clause is improper because
in operation, it would be single-issue ratemaking. All of the parties cite statute or case law in
43
favor of their positions, while the Company asserts to the contrary. The OTS statement on this
issue is quite succinct:
Furthermore, the proposal offered by the Company
constitutes single-issue ratemaking as it would allow PPL to
increase rates up to 5% based on a single isolated aspect of its
operation. As OTS Witness Gruber has correctly identified, any
proceeding that only investigates a single change is one-sided. All
proceedings that affect rates should include an examination of all
factors included in the utility’s revenues and expenses. Any
variation from this standard would alter the fundamental intent of
rate base/rate of return regulation. OTS Statement No. 5-SR, p. 6.
OTS MB at 64. The Commission has not favored similar arguments in its DSIC and CSIC
Orders. E.g., CSIC Order, Slip Opinion at 14 (not tantamount to disassembling the ratemaking
process.)
This would not be a single-issue ratemaking process, because there will be issues
of depreciation, return and income taxes (although these are not supposed to be income
producing projects). However, this point is a bit of a quibble. The parties argue that these issues
are usually heard in a context of the entire company operations, and there would be insufficient
context in these proceedings to allow a full or adequate review. The ALJ agrees. However, the
ALJ notes that traditional rate base/rate of return regulation must be subject to change as the
transition to a restructured industry takes hold.
PPLICA actually opposes the DSIC on several grounds. It asserts that the DSIC
must be rejected because it would eliminate regulatory review and provide PPLEU with the
potential to over earn on its rate of return, as well as because it would result in single issue ratemaking.
Finally, PPLICA objected to collection of the DSIC on a kWh basis. According
to PPLICA, this method of collection does not track with cost causation, and would exacerbate
the already significant subsidy problem with PPL’s distribution rates. However,
44
During the course of this proceeding, PPL has recognized
that recovery of DSIC expenses based upon a kWh allocation
would tend to recover more DSIC costs from large customers. See
PPL Statement No. 4-R at 15. To address this problem, PPL has
indicated a willingness to calculate the DSIC as a percentage to be
applied to distribution rates. Under this alternative methodology,
DSIC recoveries would follow the Commission’s allocations of
plant in this proceeding as reflected in rates for distribution
service. Id.
While this modification does not render the DSIC just or
reasonable, PPL’s alternative would at least reflect a DSIC
mechanism that is more equitable from a rate structure standpoint.
Accordingly, while PPL’s DSIC continues to be unjust,
unreasonable, and contrary to statutory requirements, if the
Commission does approve the DSIC, PPL’s revised rate recovery
approach should be adopted in lieu of a kWh recovery mechanism.
See PPLICA Statement No. 1-S at 8.
PPLEU MB at 58.
OCA argues that there is insufficient Commission overview:
The Company also attempts to argue that there is sufficient
regulatory review built into its process to overcome any concerns.
PPL M.B. at 130-131. The regulatory review, which the Company
envisions, however, is extremely short. The Company’s proposal
is to file its DSIC on December 1 of each year and have it go into
effect on January 1 – one month later. This stands in stark contrast
to the 9-month time period provided for the base rate review of
such capital investment in a traditional base rate proceeding. In
that one month, the Commission Staff and the parties would, at a
minimum, have to evaluate the purpose of the projects, audit
whether the projects met the eligibility criteria for inclusion in the
DSIC, and determine if the projects were non-revenue producing.
See, e.g., OCA St. 2 at 7-8. PPL’s proposal provides little
meaningful opportunity for review, thus reducing or eliminating
proper oversight of PPL’s rates.
OCA RB at 82.
The ALJ opines that this is short even when compared to the abbreviated time
periods in 1307(e) filings, or those allowed in annual 1307 (f) filing review periods. The ALJ
agrees the proposed time period is too short for meaningful regulatory review.
45
D.
Additional Conclusions on the DSIC
The ALJ does not agree that PPLEU’s electrical system and the water and waste
water systems where the DSIC and the CSIC were created are comparable4. For one thing,
electricity is inherently dangerous at most of the Company’s transmission and distribution levels,
and water is not. Second, while its rate of return may have declined under the rate cap, the
Company has not argued that it was inadequate before that time, and it has maintained its quality
of service and received awards for it. Moreover, as a result of this rate case, it will receive a new
rate of return which will be intended to be adequate.
Pennsylvania American (now Aqua America) has recently acquired both water
and sewer companies and/or systems which apparently need improvement to become adequate.
CSIC Order, Slip Opinion at 16-18. PPLEU has not acquired new service territory, or preexisting companies, and in fact has divested itself of facilities. The need for the DSIC and CSIC
was not based on the rate of return levels but on deteriorated facilities. PPLEU does not contend
that its facilities are deteriorated, but that it has many aging facilities that should be replaced.
The ALJ notes that PPLEU participates in a partially competitive industry, the
deregulated wholesale power market, and Aqua America does not. The ALJ opines that, even
considering the cost of generation, and even after the rate cap comes off, the DSIC would make
the price-to-compare harder to calculate, and that it would introduce uncertainty into choices
between providers in the long term.
Also, the Company has not proposed a sunset date for this clause. The need for
repairing and replacing aging plant from the 60’s, 70’s and 80’s should come to an end. By
4
The ALJ disagrees with OTS and agrees with the Company as to whether a substation is part of
the Company’s distribution system. Many substations exist to step down power from transmission level to a
distribution level, or to send power from one part of the distribution system to another. The Company states that
most of the electricity distributed by PPLEU to customers flows through substations. PPLEU MB at 129-130. The
Company asserts “PPLEU’s DSIC applies only to equipment that replaces existing deteriorated or failed substation
equipment”. New substation equipment is expressly excluded from the proposed DSIC. Id. The ALJ gathers that
the pumping station in question was a new addition to be constructed for the water treatment and storage system, not
an older pumping station that was being refurbished for the distribution system. Id.
46
comparison, in relation to the TSC, the Company will always need to purchase transmission
services from PJM, or some other RTO, or from some other Company. It will be a permanent
feature of the reorganized industry, at least for PPLEU, which has divested itself of its generation
facilities.
For all these reasons, the ALJ does not recommend that the Commission allow the
Company to establish its DSIC as proposed. However, the ALJ opines that there would be great
value in a properly designed and approved DSIC. In a new competitive market place, procedures
should be streamlined, but still meaningful. Proper Commission oversight could be built in,
perhaps mini-reviews annually or biennially. There should be no need for the Company to file
another rate case in 2 years, which it apparently now plans to do. It is costly and time consuming
for all parties. The ALJ opines that the DSIC should have a sunset provision built into it, and
that a convenient date would be December 31, 2009, when the generation rate cap expires.
The ALJ would recommend that a properly designed and approved DSIC be approved by the
Commission after legislative input.
VI.
1.
EXPENSES
INTRODUCTION-RATE CAPS
Regarding the two major litigated expense issues, PPLEU and OCA argue
different interpretations of the rate cap in the Electricity Generation Customer Choice and
Competition Act, (Act or Customer Choice Act), 66 Pa.C.S. §§2801, et seq., 2804(4)(A)(iii);
differing interpretations of the Court and Commission rulings found and discussed in Arippa v.
Pa. Public Utility Com’n, 792 A.2d 636 (Pa. Cmwlth. 2002) (ARIPPA); and both rely on
provisions of the Joint Petition for Full Settlement of PP&L, Inc.’s Restructuring Plan and
Related Court Proceedings (Joint Petition or Settlement), found in OCA’s Main Brief, Vol. 2,
Appendix C.
47
Section 2804(4) (A) (iii) provides that:
§2804. Standards for restructuring of electric industry.
* * *
(4)
The following caps on electric utility rates shall apply:
(i)
For a period of 54 months from the effective date
of this chapter or until an electric distribution utility is no
longer recovering its transition or stranded costs through a
competitive transition charge or intangible transition charge
and all the customers of an electric distribution utility can
choose an alternative provider of electric generation,
whichever is shorter:
(A)
The total charges of an electric distribution
utility for service to any customer who purchases
generation from that utility shall not exceed the total
charges that have been approved by the commission
for such service as of the effective date of this chapter;
and
(B)
For customers who purchase generation from
a supplier other than the electric distribution utility, the
charges of the utility for non-generation services that
are regulated as of the effective date of this chapter,
exclusive of the competitive transition charge and
intangible transition charge, shall not exceed the nongeneration charges that have been approved by the
commission for such service as of the effective date of
this chapter.
* * *
(iii) An electric distribution utility may seek, and the
commission may approve, an exception to the limitations set
forth in subparagraphs (i) and (ii) [relating to recovery of
transition or stranded costs] only in any of the following
circumstances:
(A)
The electric distribution utility meets the
requirements for extraordinary rate relief under section
1308(e) (relating to voluntary changes in rates).
48
(B)
Either the electric distribution utility is
required to begin payment under contracts with
nonutility generation projects that have received
commission orders, has been unable to mitigate such
costs, such costs are not recoverable in a competitive
generation market and such costs were not previously
covered in the competitive transition charge or
intangible transition charge, or the utility prudently
incurs costs related to cancellation, buyout, buydown
or renegotiation of nonutility generating project
obligations of the utility consistent with section 527
(relating to cogeneration rules and regulations) and
such costs were not previously covered in the
competitive transition charge or intangible transition
charge. Costs related to cancellation, buyout,
buydown or renegotiation shall be recovered from
ratepayers over a period not to exceed three years,
unless the commission determines within its discretion
to require a longer recovery period due to the
magnitude of such costs, but shall be accounted for by
the utility on a levelized basis over the total period in
which the generation portion of the utility’s rates are
capped.
(C)
The electric distribution utility is subject to
significant increases in the rates of Federal or State
taxes or other significant changes in law or regulations
that would not allow the utility to earn a fair rate of
return.
(D)
The electric distribution utility is subject to
significant increases in the unit rate of fuel for utility
generation or the price of purchased power that are
outside of the control of the utility and that would not
allow the utility to earn a fair rate of return.
(E)
The electric distribution utility is directed by
the commission or an independent system operator or
its functional equivalent to make expenditures to repair
or upgrade its transmission or distribution system.
(F)
The electric distribution utility seeks to
increase its allowance for nuclear decommissioning
costs to reflect new information not available at the
time the utility’s existing rates were determined, and
such costs are not recoverable in the competitive
generation market and are not covered in the
competitive transition charge or intangible transition
charge, and such costs would not allow the utility to
earn a fair rate of return.
49
(G)
As permitted by paragraph 16 (relating to
state tax liability)
The restructuring Settlement provides at ¶B.4. that:
The cap on PP&L’s transmission and distribution charges,
which otherwise would expire on June 30, 2001 until Section
2804(4) of the Electric Competition Act (66 Pa. C.S. §2804(4)),
will be extended until December 31, 2004, provided, however, that
PP&L may, if necessary, request recovery of additional nuclear
decommissioning expense and such expense recovery will not be
subject to any rate cap and will be treated as an exception to the
rate cap under Section 2804(4)(iii)(F) of the Public Utility Code
and such increases shall not reduce the shopping credits listed in
Appendices A and B and such increases shall be allocated to the
appropriate unbundled rate category in accordance with
determinations of the Commission. 66 Pa. C.S. §2804(4)(iii)(F).
OCA’s position is that major costs, such as Hurricane Isabel recovery and AMR
employee displacement recovery, incurred during the period that the rate cap is in effect should
be paid for out of revenues collected from rates in effect during that period. If not, there is a de
facto rate cap exception or violation. PPLEU’s position is that the Act, and presumably, also the
Settlement, talk only about changes in rates, but do not discuss collection of costs. OCA argues
that under ARIPPA, a utility may not defer costs for collection until after the end of the rate cap.
PPLEU argues that OCA misinterprets ARIPPA.
In ARIPPA, two utilities which were subject to a merger were actually seeking a
rate increase, and seeking a rate cap exception, or as an alternative, seeking to use an accounting
mechanism to shift the costs of providing its POLR service to the competitive transition charge.
The real issue was purchased power costs, because the utilities had divested themselves of
almost all of their own generation, and then found themselves at the mercy of rising prices for
electricity they needed to serve their customers. The utilities contended that the rising costs of
providing POLR service were beyond its control; the Commission agreed. The Court disagreed,
and ruled that the increases in costs were the product of previous business decisions where the
utilities could have protected themselves, and therefore they were not entitled to a rate cap
exception. The Court also ruled that collecting these costs through the CTC was improper
50
because all customers had to pay the CTC, and thus would begin subsidizing POLR service, and
thus the accounting mechanism artificially lowered the comparison for shopping customers.
The stance of the parties before the Commission in this rate case is quite different
from those in ARIPPA. PPLEU is not seeking a rate cap exception, and is seeking to collect the
disputed costs through its basic rates after the rate cap expires, not through any special surcharge.
OCA argues that PPLEU is asking for a de facto rate cap exception by asking now in this rate
case for costs that were incurred or accrued and charged in 2003 (Hurricane Isabel costs and a
pension benefit charge accrued under SFAS 88) when the rate cap was in effect.
PPLEU contends that OCA’s argument is lop-sided because it does not contest
other expenses that were incurred in that time period such as salaries. This argument is without
merit because in a rate case we are generally looking at projections based on historic expenses.
Even an adjustment proposed to reduce projected salary expense does not say the expense should
not have been paid historically, or deny that salaries are a legitimate expense for rate-making
purposes going forward. Salaries are regular recurring expenses and are paid out of regular
recurring revenue. OCA is disputing two large expense items which are, it is hoped, one-time or
very infrequent events, which the Company itself is separating out for specific rate-making
treatment and seeking inclusion in rates on close to a dollar-for-dollar basis.
These arguments seem to have lost sight of basic rate making practice before the
Commission. The Company generally uses an historic test year and a future test year as
permitted by Commission regulations. The future test year is basically projections of expected
costs based on those costs experienced in the historic test year. The future test year is used as the
basis for setting rates. Those rates are not a collection of historic costs. The rates are designed
to collect the costs that the Company will experience going forward.
However, the Commission has a long standing practice of allowing a Company to
collect some compensation for extraordinary or abnormal, large historic costs through
amortization. When past losses are amortized, an annual amount designed to be a portion of the
total is included in rates for a specific number of years, designed to allow the utility to collect for
51
the past loss. Of course, the Commission rejects amortization claims as well as granting them, so
a mere ruling that these claims are permissible as amortization claims does not mean that they
will be granted.
Although this is the first rate case after deregulation and after a rate cap has
expired, I see no need to change basic rate making procedures for regulated utility operations.
OCA would have it that amortization adjustment claims are barred by the existence of a rate cap,
presumably because OCA would oppose a company getting an exception from the rate cap based
on claims that are sought to be amortized. Neither of these claims fits into any of the exception
categories as far as the ALJ can see.
PPLEU timed the filing of its rate case very carefully. Its filing date March 29,
2004 is definitely under the rate cap, and the proposed effective date, June 1, 2004, is also still
under the rate cap, but since PPLEU knew that under Section 1308(d) of the Code, the tariffs
would be suspended for seven (7) months, it knew that its desired effective date of the rates
would be January 1, 2005, the very next day after the end of the rate cap. PPLEU was very
aware of the rate cap, had no intention of violating it, and did not perceive any need for an
exception. OCA has not challenged this course of action.
PPLEU also argues that the rate cap provision of the Code does not mention
expenses. This is not strictly true, since it does expressly establish permissibility for exceptions
for certain categories of expenses. It is true that the rate cap itself is defined in terms of charges
to customers, and bars any increase to those charges, but it certainly acknowledges that those
charges are based on costs.
PPLEU argues that prospective recovery of deferred Hurricane Isabel expenses
would not violate the rate cap. PPLEU MB at 34-37. I agree. It also argues that its proposal to
recover these costs is fully consistent with prior Commission practice and precedent. PPLEU
MB at 32-34. Here again, I agree.
52
In a recent case deciding another issue, the Pennsylvania Supreme Court parsed
the statutory provision of the Code at issue very closely.
In Elite Industries, Inc. v. Pa. P.U.C., 832 A.2d 428, 431 (Pa.
2003) (Elite), the Pennsylvania Supreme Court explained how
provisions of the Public Utility Code delineating the Commission’s
authority should be interpreted. The Court held that, in the
absence of ambiguity, the “plain language” of the statute must
control. In Elite, the Supreme Court rejected a prior judicial
interpretation purporting to read into Section 1103(a) of the Public
Utility Code, 66 Pa.C.S. §1103(a), a requirement that an applicant
for a certificate of public convenience show a public “need” for its
services. The Supreme Court found that the statute’s “plain
language,” namely, the disjunctive phrase “necessary or proper,”
did not make “need” an essential prerequisite and, therefore, the
Commission’s authority under Section 1103(a) should not be
constrained in the way prior reviewing courts had held. It
emphasized reliance on the plain wording and meaning of the
statute.
PPLEU MB at 112
The Court did, in fact, based on the disjunctive word “or,” change the meaning
that had been read into this section of the Code. Here, with the rate cap, the plain language is
clear, and there is no need to read meaning into the statute. There is no disjunctive word or
phrase in this provision. There are exceptions for certain kinds of expenses which may, if
permitted by the Commission, be collected before the rate cap expires. There is no limitation
expressed on rate case claims that may be made after the rate cap expires. Under the plain
language of the statute and the Settlement, the rate cap exists and then it expires. After
expiration, all expenses normally included for ratemaking purposes may be included in rates to
be put into effect after the rate cap expires. Before expiration, none may be collected unless they
fit under an exception. Therefore the ALJ recommends that the Commission find that the rate
cap does not bar PPLEU from making either of these claims in this rate case.
53
2.
HURRICANE ISABEL
Hurricane Isabel crossed PPLEU’s service territory during the evening of
September 19 and the morning of September 20, 2003, wreaking great damage as it went.
On October 20, 2003, under 66 Pa.C.S. §1701, PPLEU filed a Petition for a
Declaratory Order seeking authority to defer for accounting and financial reporting purposes “the
extraordinary losses that were caused by Hurricane Isabel”. By order entered January 16, 2004,
the Commission granted the Petition without giving any assurance that the deferred amounts
could be included or amortized in rates, and permitted the Company to create a regulatory asset.
OCA MB Vol 2 at Appendix C.
The claim is described by PPLEU witness Krall in PPLEU St 4 at 40-45, and is
included in Exhibit Future 1 (Rev.), Schedule D-2, D-10. The Company seeks to recover about
$15 million (regulatory asset) through amortization over 5 years, without earning any return on
the uncollected amounts. Id. at 42, 44-45. The Company reports incurring $17.2 million in costs
associated with Hurricane Isabel, but the remainder is related to capital:
PPLEU did not request deferred accounting for capital
expenditures arising from Hurricane Isabel and is not seeking to
amortize recovery of any capital items. These items are reflected in
PPLEU’s rate base as property additions that occurred in 2003.
The $15 million in expense related items includes expenditure for
the following:
 Wages including overtime
 Expenses for outside crews
 Expenses for vehicles and equipment
 Expenses for customer outreach
 Equipment charges
PPLEU St 4 at 42
54
OTS views this claim as permissible, but overstated by virtue of inclusion of
normal employee expenses, and by failure to amortize it over a sufficient length of time. OTS
presented a breakdown of the Hurricane Isabel costs:
Category of Costs
Amount
Wages & benefits – regular time
Wages & benefits – overtime
Employee meals and misc.
Vehicles and equipment
Materials and Supplies
Customer outreach
Miscellaneous
Outside crews
Total
$3,631,282
3,529,212
279,744
423,846
371,159
21,781
163,983
6,590,942
$15,011,949
OTS witness Weakley recommends removing “Wages & benefits – regular” from
the Company’s claim for these expenses because “Regular wages and benefits are ordinary
expenses that would have been incurred by PPL in 2003 regardless of Hurricane Isabel.
Therefore, they must be reversed out of the regulatory asset and included in the 2003 expenses.”
He adjusts the claim by extending the amortization to ten (10) years because:
“Major storm damage occurs infrequently over irregular intervals and it is necessary to match the
interval and the amortization period of the regulatory asset. PPL has not experienced a storm the
size of Hurricane Isabel for an extended period. Therefore, PPL must recover the allowable
incremental costs for this one-time event over an extended period of time consistent with
Commission practice.”
After reducing the regulatory asset by the amount of regular wages and benefits,
and extending the amortization period which further reduces the annual expense claim, the OTS
adjustment is5:
5
The original adjustment apparently used the numbers from PPLEU Future 1, and was not revised
according to Future 1 (Revised) The numbers here are recalculated based on PPLEU’s Future 1 (Revised), Schedule
D-10
55
Company claimed amortization
$2,975,000
Less OTS recommendations
$1,124,500
Reduction in O&M expenses
$1,850,500
OCA witness Catlin, although excluding this claim on the rate cap theory which
the ALJ has rejected, agrees that regular wages and benefits should be excluded from this claim,
and comments:
A significant portion of the $15 million of expenses which PPLEU
deferred for Hurricane Isabel were for regular and overtime
salaries and wages and the related benefits. At a minimum, the
regular salaries, wages and benefits would have been incurred
regardless of whether or not Hurricane Isabel occurred. As such,
these costs were not incremental costs which would be eligible for
deferral and recovery in rates even if the rate cap did not exist. In
addition, some portion of the overtime may also have been
incurred in the absence of Hurricane Isabel and would not qualify
as incremental costs eligible for deferral.
OCA St 2 at 12
In rebuttal, Krall refers to PPLEU’s budgeting process, and claims that since the
work it expected to get done in this time period could not get done on schedule, and it had to be
done reasonably quickly, PPLEU used overtime and contracting to get it done. He argues in
effect that the regular work hours and benefits in this claim are a proxy for the overtime and
contractors fees expended to get its regular work back on schedule. Witness Krall acknowledges
that the Company rarely experiences storms such as Hurricane Isabel; in fact he admits that the
Company has not experienced such a storm for 80 years, but argues that a lengthened
amortization is inappropriate. However, Krall has no rationale for selecting a five (5) year
period. He does point out that since the Company is foregoing return on these amounts,
lengthening the amortization period deprives it of return for that much longer. PPLEU St 4-R at
38-39
56
OTS vigorously disputes the rebuttal changed characterization of this claim as
improper, and without basis. It points out that the claim already includes amounts for contractors
and overtime. It asserts that the Company has not met its burden of proof to support this claim as
a proxy for overtime and contractors fees.
While the Company supported its claim against OTS’s proposed adjustment in its
Main Brief, presenting essentially the same arguments as witness Krall, for inclusion of the
regular wages expense because of Company budgeting procedures, and against a 10-year
amortization period because of lack of an earned return, it does not present any opposition in its
Reply Brief. It concentrates its arguments against OCA’s interpretation of the rate cap, and the
ALJ has already agreed that the rate cap does not bar this claim.
The ALJ agrees with Messrs. Weakley and Catlin that the regular wages and
benefits should be removed. They should not be regarded as a proxy for expenditures to catch up
with budgeted work. In fact, in the face of Hurricane Isabel, the Company might have been
expected to revise its work budget just a little bit. As to the length of the amortization, I believe
that the Commission’s practice is to try to match the amortization period to some extent with the
timing of the outstanding event causing the expense that is to be amortized. This is certainly true
with rate case expense amortization.
The ALJ recommends that the Commission adopt the revised OTS adjustment to
this claim as set forth above.
57
3.
EMPLOYEE SEVERANCE COSTS RESULTING FROM IMPLEMENTATION OF
THE AUTOMATED METER READING PROGRAM
PPLEU has initiated a far-reaching and ambitious installation program, to convert
all meters measuring electricity consumption by all of its 1.3 million customers to an Automatic
Meter Reading (AMR) system. Deployment began in Spring 2002, and:
This program requires replacing existing meters with new
or retrofitted meters and installing communications equipment that
permit meters to be read automatically and that communicate
usage information through PPLEU’s power lines. Installation of
the necessary equipment is expected to be completed by September
30, 2004. PPLEU St. 4, pp. 10-11.
The necessary equipment includes “installation of communications equipment at
over 300 substations, the modification of meter data systems and billing systems to permit
readings obtained in this fashion to be used for billing. For most of its customers, the data will
travel over the power lines after the meter is prompted by a communications server. For
customers served at high voltages where the communication cannot survive the voltage
transformation, wireless communication will be used.” PPLEU MB at 40; PPLEU St 4 at 10-11
There are a number of benefits of this installation. There will be service
enhancements. The new system should improve reliability of service. Also, the AMRs have
enhanced capabilities that will enable PPLEU to be able to develop additional functions in the
future. There are certain calculable economic benefits from reduced direct cost metering
expenses, primarily from the reduction of the meter reading workforce. PPLEU MB at 41-42
These savings equate to a net present value of $205 million over a
fifteen-year period. In contrast, the net present worth of the $160
million investment in the AMR system over the same fifteen-year
period, is only $198 million. This comparison, however, includes
only the direct economic benefits of the AMR system and therefore
does not reflect the full range of benefits from this new system.
PPLEU MB at 42
58
One effect of the installation of the AMRs is to reduce the need for manual
reading of meters on a regular and on special bases. This means the elimination of many jobs.
PPLEU has been able to place many of its meter readers in other jobs in its work force, but it has
terminated 96 workers, and offered them enhanced severance packages. The amount of the
severance packages is said to total $8,818,000 which PPLEU took as a one-time expense accrual
in 2003. PPLEU proposes to amortize it over 5 years for an increase in distribution operating
expense of $1,764, 000 in each of those years.
The program, its benefits, and the need for the severance benefit package is
described by PPLEU witness Krall in St 4 at 10-17, and the recovery of displacement costs is
described by him in the same statement at 17-19. The amount of the claim is found in Exhibit
Future–1 (Revised), Schedule D-9.
OCA argues that the program does not have a net economic benefit based on the
figures presented by PPLEU:
According to the response to OCA III-8, the net present worth of
the benefits of the AMR program are expected to be $202 million
and the net present value of the costs are $197 million. Hence,
PPLEU has identified a net benefit of the program of $5 million
dollars over the next 15 years. However, in calculating these net
benefits, PPLEU did not include the one-time pension benefit
termination charge. The net present value of those one-time costs
based on the Company’s proposal to amortize them over five years
with no return is approximately $7 million dollars. Hence,
allowing PPLEU to amortize the pension benefit termination
charge in rates would result in ratepayers bearing costs which
exceed the benefits of the AMR program. That is, ratepayers
would be better off [economically] without AMR if the
amortization of the $8,818,000 was allowed.
OCA St 2 at 13 (Witness Catlin)
PPLEU argues that this approach is mistaken because it assigns $0 value to the
enhanced quality of service that will flow from the new system both immediately and over time.
In both Main and Reply Briefs, the Company asserts that:
59
These improvements include elimination of estimated bills and
elimination of the need for customers to arrange for manual meter
readings for final bills. Service reliability will be enhanced
because the AMR system will allow PPLEU to diagnose
distribution system problems and determine whether problems in a
particular distribution system area have been resolved. In addition,
the AMR system will provide a platform to support programs that
will benefit customers in the future, including programs that will
enable customers to save money by using electricity during low
cost periods.
PPLEU MB at 42-43.
The ALJ agrees with the Company that a net present worth analysis does not
include the value of modernizing the meter reading system, and the various benefits that will
accrue to the Company and its customers. The ALJ notes that it was the Company itself which
brought such an analysis into the picture, and that the OCA is correct that the expense accrual in
this claim should be included in such an analysis. Nonetheless, the ALJ opines that installation
of the new system is in the interest of the Commission, the Company, and its customers.
The Company also urges this claim because the customers will receive most if not
all of the benefit from the new system, and therefore they should pay these costs of installation.
The ALJ is sure that the costs of all the components of the new system are included in the rate
request, and is sure that the customers are going to bear the costs of this new system. Moreover,
the ALJ opines that this new system will also benefit the Company directly, perhaps in preparing
to meet competition. On matters like these, the Company and customer interests are so
intertwined that they are hard to separate.
OTS opposes this claim altogether because
...the benefits to be paid to separated employees including
enhanced early retirement benefits and a one time special
separation allowance ... will be paid from the PPL Retirement Plan
pension trust. The pension trust is an entity separate from the
Company. Therefore, PPL’s Automated Meter Reader
displacement costs claim should be rejected since this claim will be
paid by the pension trust and ratepayers have already paid these
costs through past pension expenses included in base rates.
60
OTS St 2 at 20 (Witness Weakley)
The Company denies that its customers have already paid for this expense
accrual. It asserts that this expense accrual is incremental to the pension costs that were
approved in the 1995 case, because the AMR displacement costs were not contemplated in 1995.
The Company then points out that the pension costs are actuarially calculated under SFAS 87 as
a recurring expense, while the AMR benefit was actuarially calculated under SFAS 88 as a onetime expense, and are recovered independently.
In its Reply Brief, OCA counters one of PPLEU’s argument in support of this
claim as follows:
Finally, PPL argues that whether it makes a cash outlay or
not, is irrelevant, analogizing this argument to the recovery of its
pension expense. PPL M.B. at 45-46. PPL’s analogy does not
work in this instance. The termination charge at issue here is a
one-time accrual under FAS 88, which did not require a cash
outlay by the Company because the pension trust fund balance
is over funded. OCA St. 2 at 12. As noted by Mr. Catlin,
depending on the performance of the pension trust fund, PPL may
never be required to make a cash contribution. OCA St. 2 at
14. The FAS 87 pension accrual is an annual accrual, not a onetime accrual, which is intended to account for the annual pension
obligations incurred on behalf of PPL’s entire workforce.
(Emphasis added) OCA RB at 16.
OCA witness Catlin also opposes this claim partly on the basis that no cash
payment was made, or required:
...First, I would like to note that the $8,818,000, pension
termination benefit charge was an expense accrual and did not
require a cash outlay by PPL. Depending on the performance of
the pension trust fund, it is possible that PPLEU may never be
required to make a cash contribution to fund this expense.
61
Second, I would like to note that the OCA’s position that recovery
of the pension termination benefit charge be denied will have no
effect on PPL’s displaced employees. The termination benefits to
those employees have already been assured and will be paid from
the pension trust fund. As noted above, PPLEU was not required
to make a contribution to the trust to fund these benefits.
OCA St 2 at 14 (Witness Catlin).
The ALJ concludes that this is not a proper claim for amortization. This is not a
large expense that has been paid, or a large loss that requires devotion of a concentration of the
Company’s resources to overcome. This is in effect a virtual expense which was neither paid nor
incurred by PPLEU. Amortization was not designed to cover this kind of expense.
The ALJ recommends that the Company’s claim for recovery of $8.8 million of
AMR displacement costs should be rejected. Since no payment was made, and none may ever
have to be made, PPLEU should submit a claim in a rate case when and if that payment is
required. This adjustment reduces future test year expense by $1,764,000 and increases net
income after income taxes by $1,032,000. OCA St. 2 at 14; OCA St. 1, Sch. LKM-8S.
4.
EPSTEIN ADJUSTMENT
PPLEU addresses separately the arguments of Complainant Epstein (Epstein or
Complainant) who also opposes PPLEU’s amortization of AMR severance costs but on different
grounds that OCA and OTS. Since the ALJ has already recommended that the Commission
reject the Company’s claim, she will only briefly touch on the basis for his adjustment.
Epstein takes the position that the layoffs occasioned by the introduction of
AMRs harm the employees laid off, and that these employees are members of the community,
and that the community will be further harmed by the loss of income that these employees
earned. It is in this context that he contends that customers should not have to pay to fund
layoffs and underwrite costs of a program that will produce small benefits to customers. Epstein
St. 1, pp. 5-6.
62
The Company argues that Epstein’s arguments are without merit. From the
Company’s position the contentions have no merit because the Company only sees this program
in terms of benefit to the customers through reduced payroll expense and other expenses, which
should reduce rates. Of course, the fact is that through paying for the severance costs, as pointed
out by OCA, there is very little net benefit for rate payers.
However, as proposed by Epstein, this adjustment and its basis, i.e., community
harm, are not cognizable for purposes of ratemaking.
5.
PENSION EXPENSE
PPLEU initially budgeted $1,477,000 of its pension expense to operation and
maintenance expenses in this proceeding. PPLEU MB at 49. OCA and OTS both have proposed
adjustments to PPLEU’s pension expense.
OCA and the Company no longer have a dispute about pension expense:
OCA’s adjustment of $491,000 was based upon an
actuarial report prepared on behalf of PPLEU, which showed a
reduced pension expense. PPLEU has agreed that OCA’s
proposed adjustment to pension expense, based upon the updated
actuarial report, is proper and has reflected that adjustment in Ex.
Future 1 (Revised). PPLEU St. 2-R, p. 4; OCA St. 1-S, p. 2.
There is no controversy between OCA and PPLEU concerning
pension expense.
OTS proposed to eliminate the Company’s pension expense claim (and also the
capitalized portion of the pension claim) in its entirety. OTS’ sets forth its proposal as follows:
PPLEU claimed gross pension costs of $2,662,000 for the 2004
future test year is based on an allocation of the SFAS 87 amount
attributable to PPLEU’s participation in the PPL Retirement Plan
and PPL Supplemental Executive Retirement Plan (SERP). This
total $2,662,000 is divided as follows:
63
Gross pension cost
Distribution (94.59%)
O&M Allocation (69.5%)
Rate Base (30.5%)
PPL
Retirement
Plan
PPL
SERP
Total
$2,125,000
$2,010,038
$1,396,976
$613,062
$537,000
$507,948
$353,024
$154.924
$2,662,000
$2,517,986
$1,750,000
$767,986
The distribution amounts are the gross pension costs less the costs
allocated to transmission. The distribution amount is further
allocated to O&M and rate base. These allocations are based on
the time worked on expense and capital projects.
OTS St 2 at 11
OTS asserts that two separate adjustments are required to ensure that the effects
of this claim are removed from both expenses and rate base: “The Company’s expense claim of
$1,396,976 should be denied and the corresponding capitalized portion of the expense of
$613,062 must be removed from rate base.”
OTS objects to this claim because it is based on SFAS 87, which applies to annual
accruals, and is an accrued expense6. No actual payments into the pension fund are required
under this standard and none are made by the Company. The amount of payment is controlled
by IRS deductibility and the minimum requirements of the Employee Retirement Income
Security Act (ERISA). Both the IRS maximum and the ERISA minimum are zero, and so no
payments are made. OTS MB at 23. OTS regards collecting money from ratepayers for
payments that are not made creates a windfall for the Company. OTS stresses that, as the
Company acknowledges that, PLEU has made no payments into the pension fund for the last ten
(10) years, even though it has been collecting monies for pension expense since the last rate case
in 1995. OTS argues that in recent cases, utilities before the Commission have based pension
expense on actual payments. “See, for example, Pa. P.U.C. v. Aqua Pa., Docket Number
R-00038805, Pa. P.U.C. v. Pennsylvania-American Water Company, Docket Number
6
Unlike SFAS 88 which is a one-time payment standard, which is part of a prior disputed
adjustment.
64
R-00038304. This type of recovery allowance ensures that only actual expenses are being
recovered and ratepayers are protected.” OTS MB at 23
The Company asserts to the contrary that in these cases the pension expense was
not in dispute, but that the OTS position here is the same one that it took in the last PPL rate
case, and directly contrary to the ruling the Commission made there where this adjustment was
rejected. As the Commission stated previously:
“On review of this issue, we find the recommendation of
the ALJ that the Company’s claim for this item be accepted to be
in accord with the evidence as developed in this proceeding. We
note that pension expense tends to be an extremely variable cost
from year-to-year. As noted by the ALJ, consistent use of the
accrual should be fair to both rate payers and stockholder, over the
long term. Further, consistent use of the actuarial method will,
over time, provide for a more consistent and less variable expense
element. We agree with the Company’s position that it makes no
sense to calculate pension expense on a cash basis but to calculate
retirement benefits other than pensions on an accrual basis.
“For these reasons, the Exception filed by the OTS on this
issue is denied.” (Emphasis in original.)
Pa. P.U.C. v. Pennsylvania Power & Light Co., 85 Pa. PUC 306, 329 (1995).
However, when the last rate case was filed, contested, and decided, PPLEU was
Pennsylvania Power & Light Company, a fully integrated electric utility providing distribution,
transmission and generation service, and electric industry restructuring had not occurred. But
OTS has made no argument that changed circumstances make its adjustment appropriate now,
when the Commission found it inappropriate before. I can see no reason why changing pension
expense would help streamline PPLEU for competition.
Moreover, despite the change in circumstances, the Company argues that
“Fairness to ratepayers and shareholders requires that the basis for calculating pension expense
65
be consistent over time. The OTS should not be allowed to change from one ratemaking
methodology to another simply to produce a desired end result.” The Company also argues:
On an accrual basis, under SFAS No. 87, PPLEU has a current
future test year pension liability of approximately $75 million. Tr.
440. This liability must be paid in the future, in cash. The fact
that PPLEU has not made cash payments in recent years is solely
the result of IRS rules regarding the tax deductibility of pension
plan contributions. It does not reflect PPLEU’s actual pension
obligations. Indeed, the lack of cash contributions despite an
actual pension expense liability of $75 million fully supports
PPLEU’s and the Commission’s use of SFAS No. 87 to establish
pension expense.
(Emphasis in the original) PPLEU MB at 51.
The ALJ recommends that the Commission adopt the Company’s pension
expense claim, and reject the OTS proposed adjustment.
6.
THE DEPARTMENT OF DEFENSE’S PROPOSED ADJUSTMENT TO INJURIES
AND DAMAGES EXPENSE 7
PPLEU’s injuries and damages expense is established as part of a thorough and
detailed budget process that is explained at PPLEU St. 2 at 13-17. The US DOD has proposed to
reduce PPLEU’s future test year injuries and damages expense of $1,517,000 to $1,169,000. US
DOD St. 1 at 9. The US DOD adjustment is based solely on the fact that $1,169,000 was the
actual historic test year level of injuries and damages expense. The Company argues that US
DOD’s proposed adjustment should be rejected. The ALJ agrees.
The Company asserts that the historic test year level for this expense was
abnormally low. Actual injuries and damages expenses were $1,374,198 and $1,325,470 for
2001 and 2002, respectively. PPLEU St. 2-R at 16-17. There is no basis for believing that
7
In this and the next six Expense items, the ALJ has relied on the Company presentation. She has
made a number of additions and deletions, but she has relied on the Company Main Brief for the structure and
sometimes the content of the discussions.
66
PPLEU’s injuries and damages expense will remain at the historic test year level of expense.
While there is no basis to believe that it will increase to a specific higher level, it is reasonable to
expect some inflation, and some other increases. The ALJ finds that this amount was derived
from the budget process, and is a reasonable amount.
7.
THE DEPARTMENT OF DEFENSE’S PROPOSED ADJUSTMENT TO PPLEU’S
EMPLOYEE HEALTH INSURANCE EXPENSE
US DOD has proposed to reduce PPLEU’s employee health insurance expense by
$1 million. PPLEU self insures this employee benefit. PPLEU St. 2-R at 17-18. US DOD’s
proposed adjustment is based on the fact that there is projected to be a liability reserve of
$3,573,000 at the end of 2004. US DOD proposes to reduce this reserve by refunding $3 million
of the reserve to customers over a three-year period. US DOD St. 1 at 9. US DOD’s proposed
adjustment is incorrect because it fails to recognize that the reserve simply reflects a timing
difference in the incurrence and recording of health care costs for accounting purposes and does
not reflect any over collection or inflation of health care costs.
The amount of the reserve has nothing to do with PPLEU’s ratemaking claim for
employee health care. PPLEU’s ratemaking expense for this purpose is $18,838,000, which is an
estimate of the future test year expense based on levels of the expense in prior years. In 2001,
2002, and 2003, the actual expenses were $17,903,000, $19,540,000 and $16,968,800,
respectively. PPLEU St. 2-R at 19. No party, including US DOD, has challenged the
reasonableness of PPLEU’s total claim for employee health care expense. US DOD’s proposed
adjustment is based solely on a temporary timing difference and therefore is invalid.
Specifically, US DOD ignores the fact that, as a result of the normal processing of
employee claims for medical benefits, there is a lag or delay between the time an employee
receives medical care and when PPLEU pays the claim. Generally Accepted Accounting
Principles (GAAP) in the United States require an accrual for the estimated cost of medical
services that have been rendered as of the close of a financial reporting period but which have
67
not yet been paid. Such costs are termed “incurred but not reported” employee medical health
care expenses. PPLEU St. 2-R at 17-18.
PPLEU’s projected reserve for the end of the future test year is the same as the
actual reserve at the end of the historic test year. Thus, PPLEU has projected no change in the
level of the reserve from the beginning to the end of the future test year. PPLEU asserts that its
reserve of $3,573,000 is reasonable and appropriate. The ALJ agrees.
8.
PPLEU’S REVISED ENVIRONMENTAL EXPENSE CLAIM
PPLEU initially claimed $3,556,000 for environmental remediation expense.
OCA, OTS, DOD, Strategic Energy and Epstein all challenged this expense. In particular, OTS
criticized “[t]he Company’s original Environmental Remediation expense claim [as being]
unsupported and overstated,” and asserted that its original test year claim of $3,556,000 should
be rejected entirely. Upon review of the opposing party testimony, PPLEU proposed to reduce
its claim to $1,073,000. This adjustment reflected a three-year average of environmental costs,
instead of a one-year projection. PPLEU has reflected it in Exh Future 1 (Revised). OTS and
OCA now accept the claim. OTS states:
Based on Rebuttal Testimony, OTS agrees with the Company
revision of this expense claim to $1,073,000. This revision results
in a decrease of $2,483,000 to the Company’s claimed expenses.
OTS St. 2-SR at 7; OCA St. 1 at 12-13.
However, there are still three parties that oppose this claim: US DOD; Strategic
Energy; and Epstein.
Most of the environmental remediation expenses that PPLEU will incur relate to
the cleanup of manufactured gas plant sites. US DOD and Strategic Energy contend that
ratepayers may not be responsible for environmental cleanups of manufactured gas plant sites,
that some properties may have been sold at a profit that could be used to mitigate costs of
68
remediation and that these environmental remediation costs of manufactured gas plants may be
generation-related.
PPLEU responds that it has not sold any manufactured gas plants for a profit, and
asserts that US DOD’s speculation regarding other sources of funds for environmental
remediation is simply mistaken. PPLEU St. 2-R at 14. [US DOD did not file a Reply Brief to
challenge this statement, so the ALJ recommends that the Commission accept it.]
The Company asserts that it is completely appropriate for ratepayers to bear the
costs of environmental remediation at manufactured gas plant sites. According to the Company,
historically, utility companies, including some PPLEU predecessors, manufactured gas from coal
and petroleum products, and delivered it to customers. As the industry evolved to supplying
natural gas, over time, utilities discontinued manufacturing gas, but continued to operate local
distribution systems to supply natural gas to customers.
Under various state and federal laws, PPLEU may be
wholly or partially responsible for the remediation costs at certain
facilities that were owned and operated by the Company or its
predecessors. Consequently, these liabilities remained with
PPLEU during its restructuring proceeding in 1998. Such sites
were clearly used to provide public utility service, and customers
should pay for costs of remediating those sites.
PPLEU MB at 52
Epstein has contended that the initially estimated remediation cost was excessive
because, in his opinion, it was based upon experience at a single site and was beyond what was
needed to complete a cleanup of PCBs at that site. Epstein appears to be referring to the costs for
remediation of the former Sunbury manufactured gas plant site. “PPLEU did use its experience
at the Sunbury manufactured gas plant site as a basis for its initial estimate of remediation costs
to be recovered in this proceeding. However, that site did not include any work or costs for PCB
clean up. PPLEU St. 2-R at 14. Accordingly, work at that site was an appropriate basis for
PPLEU’s estimate”. Moreover, PPLEU has revised its initial claim, and Epstein has not
responded to that revision.
69
The ALJ recommends that the Commission accept the revised environmental
remediation expense claim of $1,073,000.00. PPLEU MB at 51
9.
THE PROPOSED REDUCTIONS IN ONTRACK AND WRAP FUNDING BY OCA
AND OTS
Both OCA and OTS have proposed reductions in PPLEU’s request for additional
funding for OnTrack, PPLEU’s customer assistance program. Actually, they have proposed to
normalize this expense on a two-year basis. They propose to limit any increase in OnTrack
funding to $13.2 million, the average of the amounts PPLEU proposes to spend in 2005 and
2006, the first two years of PPLEU’s “ramp-up” period. OCA St 5 at 37; OTS St. 2 at 29-30; Tr.
856-57. OTS has proposed a similar reduction for WRAP, PPLEU’s low-income weatherization
and solar water heating installation program. OTS St. 2 at 31-33. OTS avers that the appropriate
adjustment to the claim for these programs is $1,950,000. OTS and OCA contend that reduced
funding is appropriate because PPLEU may file another base rate case in two years, and the
Company only has expenditure plans for the ramp up period, and proposes to escrow the
remainder. See id.; OCA St. 5, p. 37. The ALJ agrees that it does not make sense to allow the
Company to collect now monies that it knows it will not be able to expend in the next two years.
Witness Dahl, responded for the Company that “the “ramp-up” period PPLEU has
proposed in this proceeding for OnTrack is consistent with the successful approach agreed to by
the parties in PPLEU’s 1998 restructuring settlement and properly reflects the challenges of
expanding these programs.” PPLEU St. 7 at 12; PPLEU St. 7-R at 25-26; PPLEU MB at 53.
PPLEU argues that its “ramp-up” period for WRAP is similarly appropriate, particularly in light
of PPLEU’s planned expansion of solar water heating installation.” PPLEU St. 7 at 12 and
PPLEU St 7-R at 21; Id.
In both OnTrack and WRAP, the funds collected in the early years will also be
escrowed and spent in later years. These escrowed funds should be held in an interest bearing
account, as suggested by OTS.
70
OTS witness Weakley proposes that PPLEU be obligated to pay interest on these
escrowed funds. OTS St. 2 at 30-31 & 33. The ALJ recommends that the Commission accept
this recommendation. The Company opposes it because Weakley opposed a return on the
unamortized balance of Hurricane Isabel cleanup costs. See OTS St. 2 at 30-31. These
adjustments are not linked in any way, or even particularly similar in content. Escrowed
accounts are often required to be interest bearing. There is no reason to mimic lack of return by
refusing to pay interest on rate-payer funds held by the Company. PPLEU MB at 54
When PPLEU does file another rate case, all parties will have an opportunity to
revisit OnTrack and WRAP funding levels. PPLEU argues that if it does not file within two
years, the Company will necessarily serve fewer customers and/or provide fewer benefits to
those customers under the universal service program funding levels proposed by OCA and OTS.
PPLEU St. 7-R at 25-26; PPLEU MB at 53-54.
The Company argues, therefore, that the Commission should approve PPLEU’s
full proposed 25.6% percent increase in OnTrack funding and 17.5% increase in WRAP funding,
without the reductions proposed by OCA and OTS.
The ALJ disagrees, and recommends that the Commission adopt the OCA/OTS
adjusted amount, but if the Commission approves the full amount, then she recommends
imposing the condition that excess funding be held in an interest-bearing escrow account.
Epstein’s Proposal for Geometric Depreciation
PPLEU’s annual depreciation accruals and accrued depreciation calculations were
prepared by Gannett Fleming, Inc. – Valuation and Rate Division in accordance with methods
and techniques that have been utilized by PPLEU and other utilities, with the Commission’s
approval, for many years. PPLEU Ex. JJS1. Mr. Epstein favors “geometric” depreciation over
standard utility methods and techniques. Epstein St. 1 at 17-19. Mr. Epstein has provided no
71
guidance on the manner in which or the amount by which use of “geometric” depreciation would
affect PPLEU’s revenue requirement in this proceeding.
Through cross examination, Epstein sought support for his “geometric”
depreciation proposal. PPLEU’s witness Spanos, however, did not provide any support for
Epstein’s proposal. Spanos, a well-recognized expert in depreciation, stated: “Well, I wouldn’t
use the geometric methodology at all.” Tr. 437. Epstein’s approach is unsupported and should
be rejected.
Epstein’s “geometric” depreciation proposal also seems to be part of his broader
proposal for market or fair value rate base. See Epstein St. 1 at 19. Epstein’s proposal should be
rejected for the additional reason that it is barred by statute. Rate base in Pennsylvania must be
based on the original cost of plant, less accrued depreciation, under Section 1311(b) of the Public
Utility Code, 66 Pa.C.S. § 1311(b).
PPLEU MB at 54-55
Epstein’s Proposal that Executive Compensation Include Consideration of
Reliability and Customer Satisfaction
In Surrebuttal, Mr. Epstein proposed that the Commission recommend to PPLEU
that a shareholder proposal, to have executive salaries be based in part on reliability of service
and customer satisfaction, be considered at the next annual meeting of shareholders. Epstein St.
2 at 14-15. Apparently, Mr. Epstein was not aware that compensation for executive officers
presently includes consideration of reliability of service and customer satisfaction. Tr. 442. Mr.
Epstein’s proposal would be redundant and unnecessary. Tr. 450. For this reason, Mr. Epstein’s
proposal should be rejected.
The ALJ opines the Epstein’s proposal for refunds to customers because of
Hurricane Isabel outages is without foundation in the regulations or the statute, and does not
72
make common sense given the enormity of the damages that the Company had to repair to
restore service. There is no evidence of undue delays.
PPLEU MB at 55
10.
OCA’S ADDITIONAL EXPENSE ADJUSTMENT8
In its Introduction, OCA stated that it would include expense claims that were no
longer disputed in its discussion.
Community Affairs Department Expenses
In its filing, the Company made an expense claim of $800,000 relating to
Community Affairs Department expenses. As pointed out in OCA witness Morgan’s testimony,
the Company submitted a data response indicating that the budgeted amount for the Community
Affairs Department should have been $500,000 instead of the $800,000 that was originally
included in the cost of service. OTS also proposed the same adjustment for this claim. Mr.
Morgan adjusted the cost of service by $232,000, which represents the Pennsylvania
jurisdictional amount to remove the excess costs. OCA St. No. 1-S, Sch. LKM-10S. The
Company agreed with this proposed reduction. PPL St. No. 2-R at 10.
Expiring Amortizations: Power Management Software and Amortization of
Deferred Taxes Relating to Removal Costs.
PPL has included an expense claim of $529,587 for the amortization of power
management system software. However, OCA witness Morgan and OTS witness Weakley
pointed out, these costs will be fully amortized at the end of 2004 and should, therefore, be
removed from the revenue requirement calculation. OCA St. No. 1 at 12; OTS St. No. 2 at 23.
The Company agreed to eliminate the amortization claim for the power management
8
These discussions of expense adjustments agreed to by the Company are essentially excerpts from
OCA’s Main Brief.
73
software. The Company has no plans to purchase any other capitalized software that would be
amortized in 2005. PPL St. No. 2-R at 8.
After an exchange of discovery responses and information in direct, rebuttal and
Surrebuttal testimony, between OCA witness Morgan and Company witness Schadt:
To correct the adjustment proposed in his direct testimony, the
OCA submitted revised schedules in which Mr. Morgan made an
adjustment reducing the amortization of the deferred taxes relating
to the cost of removal by $70,000 instead of the $177,000
proposed in his direct testimony. Since the $70,000 adjustment
reduces the deferred taxes being flowed back to ratepayers, Mr.
Morgan’s adjustment resulted in a $46,000 increase in deferred tax
expense after the Pennsylvania jurisdictional allocation factor is
applied and results in an increase to the Company’s revenue
9
requirement. OCA Sch. LKM-11S Revised.
OCA MB at 35-36 (Footnote included below)
Environmental Remediation Expense
The OCA adjustment was included in the discussion above on environmental
remediation.
Social Programs
OCA witness Roger Colton has reviewed the Company’s proposals for its
universal service programs. Mr. Colton’s recommendations for the level of costs to be
recognized as expenses in this proceeding are discussed in Section IX of OCA’s Main Brief. Mr.
Colton made recommendations concerning the Company’s OnTrack and WRAP customer
9
Witness Morgan corrected LKM-11S attached to his Surrebuttal testimony, which reflected a debit
to deferred income taxes and would have resulted in a decrease to the revenue requirement. Morgan submitted
LKM 11S Revised, which reflects a credit to deferred income taxes and will result in an increase to the Company’s
revenue requirement. This revised exhibit was submitted as a result of cross examination of Witness Morgan. See
Tr. 488.
74
assistance programs, Operational Help hardship fund, and the Company’s community betterment
initiative. The adjustment presented by Mr. Morgan on Schedule LKM-13, which reduces
operating expenses by $1,950,000, normalizes the levels of cost related to the Company’s
universal service programs based upon the projected expenditures for 2005 and 2005. OCA St.
No. 1 at 13, Sch. LKM-13; LKM 13-S. The ALJ will discuss these adjustments when she
discusses the social programs.
Pension Expense
The Company’s claim for pension expense is based upon a preliminary estimate
of pension expense that was available at the time the rate case was being prepared. OCA St. No.
1 at 13. Based on the Company’s 2004 actuarial valuation report, which contains the most recent
pension expense data, the OCA adjusted the Company’s claim for pension expense to $489,000.
OCA St. No. 1, Sch. LKM-14S. The Company accepted Mr. Morgan’s adjustment to the
Company’s claim for pension expense given the most recent data. PPL St. No. 2 at 4.
The Company also included a claim for its Supplemental Executive Retirement
Plan (SERP). OCA witness Morgan decreased the Company’s SERP claim by $36,000. OCA
St. No. 1, Sch. LKM-14. Company witness Schadt disagreed with the extent to which the
OCA’s adjusted PPL’s SERP claim. PPL St. No. 2 at 13. Instead, the Company proposed a
$30,000 reduction, which is based on March 2004 actuarial reports. The OCA accepts the
Company’s adjustment based on the more recent data, which results in a decrease to
expenses of $491,000. OCA St. No. 1-S at 2, Sch. LKM-14S
Postretirement Benefits other Than Pension
The Company claim for postretirement benefits other than pensions (OPEB) was
$13,916,000 with $9,672,000 relating to operating expense. PPL St. No. 2-R at 2. The operating
expense portion of the claim was based on an estimate prepared by a consultant in October 2003,
which was updated on March 30, 2004. PPL St. No. 2-R at 2-3.
75
This actuarial report was corrected in July 2004. PPL St. No. 2-R at 3. Mr. Shadt
explained that with the corrected July 2004 calculation, PPL’s cost for OPEBs is $14,314,000,
with $9,948,000 relating to operating expenses. PPL St. No. 2-R at 3. After review of the
corrected actuarial report provided by the Company, the OCA accepts the revised expense
presented by the Company and the OCA adjusted expenses to include $261,000. OCA St. No. 1S at 2, Sch. LKM-15S.
A.
Interest Synchronization
OCA witness Morgan made an interest synchronization adjustment to determine
the tax-deductible interest for ratemaking. As explained by Mr. Morgan, “[t]his procedure
synchronizes the interest deduction for tax purposes with the interest component of the return on
rate base to be recovered from ratepayers. OCA St. No. 1 at 16. Mr. Morgan adjusted state and
federal income taxes by $15,000 and $49,000, respectively. Table II, Appendix A. The
Company did not object to this adjustment in its Reply Brief.
11.
OTS ADDITIONAL EXPENSE ADJUSTMENTS
In addition to the several items discussed above, OTS proposes several others for
consideration.
Community Betterment Initiative (CBI)
OTS objects to any costs for the CBI being collected from ratepayers. It argues
that the Company has failed to demonstrate that its initiative will provide a direct benefit to
ratepayers. OTS asserts that its claim for $1,000,000 must be removed. OTS RB at 18-19
The ALJ disagrees with OTS.
76
Service Corporation Charges
OTS continues to argue that: “The Company’s claim for Rate Case
Communication contained in its External Affairs Services claim must be rejected. According to
the Company’s testimony, the claim is in both External Affairs and Rate Case Expense. This
results in a double count. Therefore, the Company’s claim of $130,000 must be removed.” OTS
RB at 19
The ALJ agrees with OTS.
12.
SUSTAINABLE ENERGY FUND (SEF)
OTS asserts that there is no substantial evidence that SEF will provide a benefit to
distribution system ratepayers, and that the annual expense claim of $3,689,000 associated with
this fund must be denied. OTS RB at 20. The ALJ disagrees, and as shown by the discussion
below, recommends that the Commission adopt the Company’s SEF proposal.
The origins of the Sustainable Energy Fund are found in Section E.
Environmental Issues, sub-section E.5. Sustainable Energy Fund, of the Joint Petition for Full
Settlement of PP&L, Inc.’s Restructuring Plan and Related Court Proceedings. The cover page
gives the date of August 12, 1998. This is an extensive document totaling 51 pages, with many
sections and sub-sections. The full text of E.5. follows:
E.5. Sustainable Energy Fund. PP&L will establish a sustainable
energy fund which shall be funded from the 1.74 cents per KWH
transmission and distribution rate at .01 cents per KWH (less
applicable gross receipts tax) on all power sold for all customers
beginning on January 1, 1999 and ending on December 31, 2004,
or until the Commission establishes new distribution rates,
whichever is longer. The .01 cents per KWH shall not
automatically be considered a cost of service element upon
expiration of the transmission and distribution rate cap on
December 31, 2004. The Sustainable Energy Fund shall be
managed by an administrator designated by a seven-member Board
of Directors to be nominated by the Joint Petitioners and approved
77
by the Commission. The fund shall operate according to the
procedures set forth in its by-laws, which are to be reviewed and
approved by the Commission. The fund is to have an annual audit
and is to make semi-annual reports to the Commission and to the
parties. The purpose of the fund is to promote the development
and use of renewable energy and clean energy technologies, energy
conservation and efficiency which promote clean energy.
In this proceeding, PPL Electric has proposed that the Commission continue
funding the SEF as part of the Company’s distribution rates at its current level of 0.01 cents per
kWh from all customers for a period to end no later than December 31, 2009. PPL Electric St. 7
at 24. The Company includes $3.689 million as a distribution expense in the future test year.
US DOD 1, Exh TJP-5, line 3 (quantifying SEF claim by PPLEU)
According to the Company the purpose of SEF:
....agreed to by the parties to the 1998 Settlement Agreement, is “. .
. to promote the development and use of renewable energy and
clean energy technologies, energy conservation and efficiency
which promote clean energy.” PPL Electric recognizes that while
the parties10 to the 1998 Settlement Agreement were able to reach
agreement regarding SEF funding, that consensus no longer exists.
PPL Electric St. 7-R at 34. In effect, PPL Electric’s proposal is a
compromise position between the proposals of parties who wish to
increase the monies committed to SEF and/or change its program
and the proposals of parties who object to SEF funding and seek its
elimination. See id.
(Emphasis added) PPLEU MB at 155
SEF itself, represented by counsel, appeared in this proceeding to advocate for its
continued existence.
10
The parties listed on the first page of the Settlement that also participated in some way in this case,
or sought to intervene are: OCA, OSBA, OTS, PPLICA, Allegheny Power, MAPSA, PECO, IBEW, and GPU. I
note that CAC avers that it participated in the Settlement.
78
SEF receives all of its funding through the application of the Sustainable Energy
Fund Rider in PPL’s presently effective Tariff No. 201. The presently effective Rider is
scheduled to expire on December 31, 2004. SEF St. No. 1 at 4. The presently effective Rider
provides as follows:
SUSTAINABLE ENERGY FUND
The Company will establish a sustainable energy fund
which shall be funded from the Distribution Charges in each Rate
Schedule at the rate of 0.01 cents per KWH (less applicable gross
receipts tax) on all KWH delivered to all customers beginning on
January 1, 1999 and ending on December 31, 2004, or until the
Commission establishes new Distribution Charge rates, whichever
is longer.
SEF describes itself as follows:
SEF is a Pennsylvania non-profit corporation formed in
accordance with the terms of the Joint Petition for Full Settlement
of PPL’s Restructuring Plan and Related Court Proceedings at
Docket No. R-00973954. SEF St. No. 1 at 3 and PPL St. No. 7 at
21.
SEF has a seven-member Board of Directors nominated by
the Joint Petitioners to the Restructuring Settlement and approved
by the Public Utility Commission (“Commission”). The
Commission reviews and approves SEF’s by-laws and SEF
submits an annual audit report and semi-annual audit report to the
Commission. PPL St. No. 7 at 21-22; SEF St. No. 1 at 26; N.T.
823-825.
The purpose of the fund, as noted in PPL’s Restructuring
Settlement Agreement, is “ to promote the development and use
of renewable energy and clean energy technologies, energy
conservation and efficiency which promote clean energy.” PPL St.
No. 7 at 22. SEF’s Mission Statement is as follows (SEF St. No. 1
at 4 and PPL St. No. 7 at 22):
“Our mission is to promote, research, and invest in clean and
renewable energy technologies, energy conservation, energy
79
efficiency, and sustainable energy enterprises that provide
opportunities and benefits for PPL ratepayers.”
SEF MB at 4-5
SEF has testified to its sound business and management practices, and to its
careful metrics system used to evaluate and select projects according to a list of key factors.
SEF evaluates each proposal and quantifies the benefit to PPL ratepayers using
the following mission metrics (SEF St. No. 1 at 10):
KWHs renewable or clean energy generated; KWHs conventional
energy saved; jobs created; money leveraged; environmental
benefit, and people educated.
SEF explains how these mission metrics are used to evaluate projects, and to assure
demonstrable benefits by providing three examples. See, SEF MB at 7; SEF St 1 at 10-13.
At least two parties have proposed terminating all funding for SEF on various
grounds, including (1) that it is unrelated to distribution service, PPLICA St. 1-R, at 9-13; (2)
that it is unrelated to distribution service, and it is a hidden tax, OTS St. 5 at 5; and (3) that it
does not conform to certain federal criteria relating to life-cycle cost-effective conservation
measures or is insufficiently funded, DOD St. 2 at 7. OSBA has proposed turning over SEF
management and funds to the Pennsylvania Energy Development Authority (PEDA). OSBA St.
2 at 8.
By contrast, PennFuture has proposed increasing SEF funding to 0.02 cents per
kWh for power sold to all customers. PennFuture St. 1 at 3. Also, CEO has proposed various
program and management changes, including restricting a portion of SEF funds to photo-voltaic
systems and specific customer classes. CEO St. 2 at 16-19.
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As the Company has pointed out, agreement no longer exists as to the existence of
SEF. OTS contends that PPL is actually violating the terms of the settlement by recommending
that SEF continue. The ALJ disagrees. The agreement says that the “.01 cent per KWh shall not
automatically be considered a cost of service element upon expiration [of the caps].” OTS also
argues that there is no discernible benefit from SEF to distribution ratepayers, and states that it
has no objection to SEF so long as ratepayers do not have to fund it. PPLICA also objects to its
continued existence, or rather its continued funding by distribution ratepayers.
The ALJ disagrees with those parties that contend that collection of money for
SEF through rates is a tax. It is obviously not a hidden tax, because SEF is quite open and above
board. The tax argument must be based on the transfer of ratepayer money to another enterprise,
other than the utility itself for utility function. However, SEF’s activities are of a kind that the
Commission has encouraged utilities to perform, and they are designed to fit in with and
accentuate utility functions.
OSBA wants any new funding to be transferred to PEDA. [PEDA is an inactive
state agency that Governor Rendell is trying to revive]. OSBA takes no position on whether SEF
should be funded by ratepayers beginning January 1, 2005. OSBA posits that PEDA could
coordinate all the sustainable energy funds that were created across the state as part of the
restructuring process of most utilities. OSBA MB at 28. OSBA argues that PEDA control
would assure that the money is spent in a manner consistent with statewide energy goals and that
as a government agency PEDA can be more readily accountable for its spending priorities and
management practices than SEF. Id. OSBA is critical of SEF’s operations and achievements in
its testimony and its Briefs.
OSBA points out that SEF is supporting a large Somerset County wind farm
project, across the state from PPLEU’s territory, and contends that it has relatively few biomass
digesters, which could be useful in the rural areas of the Company’s territory. OSBA also asserts
that SEF has a vague and unfocussed internal process for selecting projects, and varied
geographic parameters. OSBA also avers that SEF is not spending the money that it has, that it
has made questionable investments in the stock market, that its administrative expenses are high,
81
and that there is uneven representation of interests on the board. E.g., OSBA MB at 29-34. CEO
would also like to see different representation on the Board.
PPLICA argues that inclusion of SEF funding as an expense in the Company’s
rates is unjust, unreasonable, and illegal. PPLICA argues that none of SEF’s projects have
produced any demonstrable benefits for PPLEU ratepayers, thereby barring inclusion of SEF
funding in rates, relying on Pa.P.U.C. v. Pa. Power & Light Co., 85 PaPUC 306 (1995), at 338,
339-40 (Commission-sanctioned funding not appropriate when there is no demonstrable benefit
in light of cost to ratepayers); and U. S. Steel Corp. v. Pa. Pub. Util. Comm’n., 390 A. 2d 865 (Pa
Commwlth 1978) at 371.
PPLICA argues that those who are proponents of SEF funding have the burden of
proof to demonstrate benefits from SEF’s projects, and clearly PPLICA includes SEF and
PennFutures, under that burden. PPLICA RB at 38, Footnote 4. The ALJ does not believe that
this is legally correct. She believes that PPL retains the undivided burden of proof on this
matter.
Nonetheless, SEF provided many examples of projects it has contributed to or
plans to develop. The brief contains an excerpt from the Overview of Mission Progress from the
2002/2003Annual report, some of which is included below:
1.0
OVERVIEW ON MISSION PROGRESS
***
[SEF’s] principal measure of impact relates to mission
accomplishment, what we are doing to promote, research, and
invest in clean and renewable energy technologies, energy
conservation, energy efficiency, and sustainable energy enterprises
that provide opportunities and benefits for PPL ratepayers. As we
complete our third year of operation, we can report that we are
making significant progress.
Several specific areas are noteworthy:
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Wind power development in Pennsylvania and elsewhere in PPL
territory
Significant growth in Leadership in Energy and Environmental
Design (LEED)-certified green buildings
Emerging electric technologies
Community economic development
Sustainable energy education
Wind Powering Pennsylvania
Encouragement and support of wind power development has been
a major theme for SEF. We believe we are a key factor in
Pennsylvania’s emergence as the major wind power state east of
the Mississippi, and in PPL’s having the highest concentration of
wind farms in the state. 
***
By the end of 2004, we expect three major new wind farms to be
operational in PPL’s territory, with some degree of SEF
involvement in all. They are as follows:
Bear Creek @ 20 MW
Undisclosed @ 40 MW
Waymart @ 61.5MW
We played the strongest role in the Bear Creek project, less than 10
miles southeast of Wilkes-Barre. We championed support amongst
the other Pennsylvania Funds and helped to broker the power
purchase agreement by PPL. Made a $1.5 million subordinated
debt commitment, complementing a further $3 million syndication,
in process, by the other Pennsylvania Funds 
***
On the demand side, we hold an equity position in CEI and provide
debt financing and a line of credit. We are one of CEI’s founding
investors, and the only Clean Energy Fund that has a programrelated investment. A number of state funds have, however,
provided grants, including New York, New Jersey, Massachusetts,
Connecticut, and Illinois, and CEI also received $3.5 million in
grants from the PECO merger 
***
83
Growth in LEED-Certified Green Buildings
Pennsylvania has the second highest number of LEED-certified
buildings in the country. We are supporting an abundance of
activity in PPL territory in various ways, as follows:
$500,000 loan to the Londonderry School, Harrisburg,
toward construction of a new LEED Silver school 
$25,000 grant to St. Stephens Cathedral School, Harrisburg,
toward construction of a LEED Silver school addition 
$19,510 grant to Eastern York School District toward
construction of a LEED-certified school and a PV
installation.
Disbursed an additional $25,000 grant to the Green Building
Association of Central Pennsylvania as a result of its
significant progress in educating professionals and building
owners in green building design.
PPL has opened a new company headquarters building that
we hope will win LEED Gold certification, which would
make it one of only two such commercial buildings in the
U.S. 
SEF St. No. 1, Attachment A; SEF MB at 9
Focusing on just one of these, the Bear Creek Wind farm, PPLICA established
that SEF did not really have any data supporting claimed congestion relief from this project, and
avers that wind farms do not improve reliability:
other regulatory bodies that have recognized that wind resources
do not provide substantial reliability benefits. The FERC has
recently acknowledged that, due to inherent shortcomings, wind
power provides minimal benefits. See generally Conference on
Supply Margin Assessment, et al., 108 FERC ¶ 61, 026 (2004).
Specifically, the FERC agreed with the assertion that “wind energy
units are also energy-limited because they have no storage
capability and because their operators have no ability to dispatch
the units on command….” Id. at P 128 (emphasis added). As a
result, the FERC held that for purposes of assessing whether an
84
energy supplier with market-based rate authority exercises
generation market power in its service area, an applicant may “derate the available capacity of wind energy units….” Id. at P 129.
In other words, because the owner of a wind farm cannot reliably
command the wind to blow, the FERC determined that any
benefits related to wind power are minimal, at best.
PPLICA MB at 26 (Footnotes omitted). PPLICA demonstrated that it had sought through
discovery information in support of Bear Creek from SEF and PennFutures, and for the
contentions about the benefits of SEF projects but received no satisfactory response. PPLICA
RB at 36-37; PPLICA Cross-Exam Exh 8-11, 13-14.
If we focus instead on the growth in LEED-certified green buildings, there seem
to be more actual results. And SEF has supported one biomass digester, and is supporting two
more (although OSBA does not think this is enough). Unfortunately, one of the projects that
SEF supported, relocating an emerging electric vehicle company to Scranton, was not successful
because their new product did not get market acceptance, and the firm went out of business. SEF
is still trying to recruit a new electric vehicle company to the area. SEF MB at 12
Also, SEF argues that the cases cited by PPLICA do not support its position. At
least one of the decisions actually approves a special rate, and SEF quotes the decision as being
in support of its position:
...Foremost in this regard is U.S. Steel Corp. v. Pa. P.U.C.,
37 Pa. Commonwealth Ct. 173, 185, 390 A. 2d 865 (1978), where
the Court affirmed a Commission Order exempting the first 500
KWH of residential usage from a PECO rate increase. The Court
concluded that the Commission’s action was “a proper exercise of
the Commission’s flexible limit of judgment in fixing rates.” The
Court in U.S. Steel explained as follows:
… Certainly there is nothing in Pennsylvania law which
now empowers the Commission to require one customer
simply to pay another’s utility bill; and, as we have
mentioned, the utility may not and could not for long be
required to provide such subsidy out of its capital. This is
not to say, however, that rate structures may not be
85
rearranged from time to time in response to changes in
economic conditions -- whether general changes or changes
especially affecting particular classes of customers. The
law presently permits reduced rates to large industrial and
commercial consumers, either because such customers buy
a lot of what the utility provides or because they may use
another's product if the price factor warrants. Pittsburgh v.
Pennsylvania Public Utility Commission, 182 Pa. Superior
Ct. 376, 126 A.2d 777 (1956). We see no reason why in
times of stringency the utility might not propose, and the
Commission might not approve, rates for residential users
less than the rates which an allocation of large increases
in necessary revenues by a strict application of cost of
service studies would suggest.
U.S. Steel Corp. v. Pa. P.U.C., 37 Pa. Commonwealth Ct. 173, 185, 390 A. 2d 865 (1978).
SEF then argues that “This same flexibility in ratemaking supports continued SEF
funding as addressed in SEF’s Main Brief, pages 14 through 16. Indeed, paraphrasing the
opinion of the Court, there is no reason, given the Rendell Administration’s emphasis on
renewable energy, why the Commission might not approve continued SEF funding in this rate
proceeding.”
The Company argues that, in analyzing whether this funding should continue, the
extended argument between several parties as to whether specific SEF projects return sufficient
distribution benefits misconstrues both the nature of the Customer Choice Act as well as
PPLEU’s role as an electric distribution company in the new competitive market place:
The Competition Act is not solely about creating a competitive
market in generation. See, e.g., 66 Pa. C.S. § 2802(12) (“Electric
industry restructuring should ensure the reliability of the
interconnected electric system by maintaining the efficiency of the
transmission and distribution system.”). And PPL Electric, as a
distribution company in the midst of Pennsylvania’s restructuring
of the electric industry, retains its POLR obligations to provide
generation to all customers who do not choose an alternative
supplier.
PPLEU RB at 82
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Actually, the Commission has long recognized that reductions in demand and energy efficiency
benefit customers, and has encouraged EDCs to establish programs that pursue these goals.
PPLEU concludes that:
SEF funding should be continued to realize these benefits in efficiency
and reduced demand from its existing projects and from projects that can
be identified in the remaining years of PPL Electric’s transition period.
Id.
The ALJ agrees, and posits that there should be a place and a role for organizations like SEF in
the new market place, to market efficiency and demand reductions to all EDCs, not only PPLEU.
PPLICA asserts that the Company should not collect funds from ratepayers on a
mandatory basis to be used to establish and support an essentially private organization. The ALJ
agrees with this basic principle. SEF does seem to have set itself up to operate in the market as a
private non-profit corporation when it becomes independent from PPLEU. And this
independence and the timing of it are truly another aspect of this dispute.
PPLICA argues that the requisite legal and/or evidentiary bases have not been
established to include the SEF costs in distribution rates. The ALJ disagrees. The standard for
proof in PUC proceedings is a “preponderance of the evidence”, not “beyond a reasonable
doubt”. PPLICA has very effectively demolished the Bear Creek Wind Farm evidence, and
exposed it as failing to show a viable project that will return benefits soon. However, there are
two other wind farms, several biomass digesters, the LEED-certificated green building programs,
etc. There is evidence of mistakes, and evidence of successes. The Company avers that it is well
run and has a strong balance sheet. PPLEU St 7 at 24. And as far as the law is concerned, I
agree with SEF’s interpretation of the U.S. Steel case as opposed to PPLICA’s; after all, this
Court did affirm the Commission’s establishment of a kind of a “lifeline rate”.
Therefore, the ALJ recommends that the Commission approve funding of SEF as
part of PPLEU’s rates in the proceeding. However, consideration could be given to setting
87
declining amounts, so that at the end of 5 years, or by December 31, 2009, funding will have
ended.
PPLEU also recommends that:
To the extent the Commission has concerns regarding issues of
program management and evaluation, project selection, or
governance, the Commission can initiate a separate proceeding [or
establish a collaborative] to address those concerns instead of
eliminating SEF funding in this proceeding.
PPLEU agrees with PLUG witness that the Commission should set standards for
SEF. PPLEU St 7-R at 42; PPLEU MB at 156.
VII.
TAXES
Details of the Company’s tax claims can be found in Exh Future-1 (Rev) at
Schedules B-5, C-6, and D-12 through D-15.
Income Taxes
According to PPLEU:
No party to this proceeding has proposed any adjustment to
income taxes. Although the amount of income taxes approved by
the Commission is subject to variation depending upon other
determinations by the Commission, including for example,
determinations on rate base and return on equity, there is no
controversy concerning the appropriate calculation of income taxes
in this proceeding.
PPLEU MB at 56
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1.
CAPITAL STOCK TAX (CST)
According to OCA “PPL included a claim for $7.2 million as the budgeted level
of capital stock tax (CST) expense for the test period. The $7.2 million is based upon the capital
stock tax formula as provided in Pennsylvania Corporate Tax Report Form. OCA St. No. 1 at
14.” OCA MB at 40. The Company’s CST claim is found at PPLEU Exh JMK 5, and is
supported by PPLEU witness Kleha. The adjusted amount is $7,820,000.00, and the increase is
$660,000.00. The Company describes its tax calculation method as follows:
In this proceeding, PPLEU has used the same method it has
used, without objection, in all prior base rate proceedings to
calculate taxes, including capital stock tax. Under this method,
PPLEU first calculates its tax liability, including capital stock tax
liability, at present rates and then recalculates or “grosses-up” tax
expense to reflect the effect of the proposed rate increase. A
detailed exhibit showing the precise manner in which PPLEU has
calculated capital stock taxes is provided in PPLEU Ex. JMK5. As
shown there, PPLEU’s capital stock tax, at proposed rates, is
$7,820,000.
PPLEU MB at 56.
Both OCA and OTS proposed adjustments to the Company’s Capital Stock Tax
claim (CST). “OCA witness Morgan proposed a decrease to the capital stock tax expense of
$2,517,000 based on the current statute and the net income component of the formula provided
on the Pennsylvania Corporate Tax Report Form. OCA St. No. 1 at 15, Sch. LKM-16.” OCA
MB at 40.
OTS proposes adjustments totaling $1,269,000.00 to distribution operation
expenses to correct the Company’s overstated tax expense.
OTS argues that “The Commission has the authority to control the amount of tax
expense it will allow a utility for ratemaking purposes, as it does for any other expense. City of
Pittsburgh v. Pennsylvania Public Utility Commission, 187 Pa. Super. 341, 359, 144 A2d 648,
89
658 (1958)”. This case does not offer strong support for the point of view that OTS argues, even
though this is an exact quote, because the Court ruled in the next sentence “Here the Commission
has properly allowed the federal income taxes based upon the actual taxes paid.” In this case, the
utility had moved to accelerated depreciation, but when it was required to pass the benefits on to
its ratepayers rather than being allowed to retain them, it reverted to straight line depreciation.
The City and other consumer interests were trying to convince the Commission to force the
utility to return to accelerated depreciation, and the Commission had declined to do so. The
Court held that “the decision to use any permissible method of determining depreciation in filing
the federal income tax return and computing the tax is largely a matter for the management of the
utility.” Id.
Both OCA and OTS calculate the Company’s tax obligation using the CST rate of
5.99 mils which was established by statute to go into effect in 2005. The Company uses the CST
rate of 6.99 mils, which is the present rate that will be reduced. Although Company witness
Kleha agreed that 5.99 mills is the rate to become effective on January 1, 2005, Kleha proposed
to include the difference between the current 2004 rate of 6.99 mills and the proposed 2005 rate
of 5.99 mills in the (STAS) filing on December 21, 2004. Kleha’s proposal arises from a
concern that the General Assembly might amend the statute at some point this year to eliminate
the capital stock tax rate reduction for 2005. PPL St. No. 5-R at 17-18. In the past, two other
similar reductions have been eliminated. If the lower rate is eliminated, no inclusion in the
STAS filing will be required.
OTS argues against this course of action:
It is senseless to use an improper rate in a rate case filing, only to
immediately adjust it in a separate STAS filing. Prudent
ratemaking requires that the Company’s use of the 2004 millage be
rejected and replaced with the established rate for 2005 of 5.99
mills.
OTS MB at 39.
90
The ALJ agrees. According to OTS, correction of this error reduces the Company’s distribution
expense claim for Capital Stock Tax by $808,000. OTS Statement No. 2, p. 41. OTS Exhibit
No. 2, Schedule 1. OCA appears to agree conceptually with this adjustment. OCA MB at 40
OCA witness Morgan also adjusts the Company’s CST claim to eliminate
reporting and paying tax on income from generating assets:
The second change that must be recognized involves the net
income component of the formula provided on Pennsylvania
Corporate Tax Report Form. As part of that formula, the future
test year and the four preceding years were averaged to derive the
net income component formula. As calculated by PPL, the net
income component includes the years 2000 through 2004.
However, when compared to other years, the net income for 2000
and 2001 were significantly higher. It is my understanding that
those years were higher because they included the results of the
electric generation operations, which are no longer part of the
Company’s business. Therefore, I have removed 2000 and 2001
from the capital stock tax calculation because it is inappropriate to
include generation costs in the cost of providing electric
distribution service. Although I removed 2000 and 2001, I have
added a projection of 2005 net income to the net income portion of
the formula. The addition of the 2005 net income recognizes that
the Company’s net income will increase as a result of a rate
increase that is granted.
OCA at 1 at 15, Sch LKM-16; OCA MB at 40.
OTS witness Weakley identifies the year 2000 as including generation derived
income based on information from the Company, but not the year 2001. OTS St 2 at 42. He
therefore removes the year 2000 from his calculation; see OTS Exh 2, Scheds 1 & 2. He also
includes an estimate for 2005 in his calculation, which he considers fair, because for purposes of
this estimate he assumes that the Commission grants the whole increase. Id. at 43. He argues
that if the 2004 liability is used to establish rates, the inflated liability caused by the 2000
generation income will remain in distribution rates until the next rate proceeding. Id. This
position has merit.
91
Also as part of his adjustment, because of the inclusion of 2005 income, OCA
witness Morgan removes the Company’s gross-up factor of $471,000.00 from the revenue
requirement. OCA St 1 at 15; Tr. 485-486; OCA MB at 41. The ALJ was not able to identify a
gross up factor of $471,000 in Future-1 (Orig) or (Rev), or in any of Witness Kleha’s exhibits.
However, PPLEU states that it does use a gross up technique. PPLEU MB at 56. The ALJ
assumes that Morgan’s amount is included somehow. But without clearer identification of the
amount of the proposed adjustment, she cannot rule on it.
OTS opposes an additional increase of $660,000 which it calls an iteration of the
CST. OTS St 2 at 44, citing Exh Future-1 (Orig), Sched D-13 at 4. Schedule D-13 at 4 in
Future-1 (Orig) shows additional operating revenue from CST of $630,000, and the same
schedule in Future-1 (Rev) shows $640,000. The ALJ presumes that this is the iteration to which
Witness Weakley refers because he says that the Company has calculated an additional increase.
He argues that this should be rejected because:
Capital Stock Tax does not increase in direct proportion with an
increase in revenues as do gross receipts tax and federal and state
income taxes. Therefore, Capital Stock Tax should not be included
on PPL Exhibit Future 1, D-13, Page 4. The effect of the increase
that the Commission ultimately grants would be an increase to
book income in the current year. The increase would be averaged
with four other years and then averaged again with 75% of net
equity. At best the effect would be 1/10 of that requested by the
Company because of the lessened impact on the CST valuation
calculation. Because of the de minimus impact, current regulatory
practice is not to iterate CST.
OTS St 2 at 44-45. This is a correct statement of the basic calculation formula for CST, and
Witness Weakley presents a persuasive rationale for not including an additional increase for CST
as per Schedule D-13 at 4. The ALJ agrees that this addition to revenues should be deleted.
Company witness Kleha contended that the net income data for 2005 should not
be included because it is inappropriate to include the incremental capital stock tax liability
92
caused by the proposed rate increase as part of the determination of the Company’s tax liability
under present rates. PPL St. 5-R at 16-17.
The Company also objected to Witness Morgan’s exclusion of the 2000 and 2001
income data, and presumably also to the OTS exclusion of the year 2000. Witness Kleha
contended that the exclusion of the 2000 and 2001 income data relating to years in which the
Company owned generation operations and inclusion of projected 2005 income is contrary to the
calculation used by the Pennsylvania Department of Revenue which determines a taxpayer’s
capital stock tax liability on the average net income for the most recent 5 years. PPL St. No. 5-R
at 15-16.
The ALJ is cognizant that the importance of this issue and this dispute is not
whether or not to allow the utility to collect revenues to cover its actual past tax liability. At this
point we are setting pro forma revenues in the historic test year to use in setting pro forma
revenues required in the future test year, in order to decide the amount that will be used in setting
rates going forward to collect revenues to cover taxes until the next rate case is filed and a new
set of rates is put in place. Therefore, the amount decided on should be forward looking, and
should allow the Company to collect the revenues it will need to pay the future CST, but should
not be set at an unrealistically high level that will be unfair to the ratepayers.
The fact is that going forward, PPLEU will have no more income from generation
facilities because the Company divested itself of these assets in 2000, and the liability is
calculated using the last five years. The fact is that going forward, according to the statute, the
tax rate is going to be 5.99 mils, not 6.99 as it is for 2004. Whether or not two past decreases
have been revoked, the fact is that the millage rate was reduced from 7.24 mils in 2003 to 6.99
mils in 2004, and the intent is to reduce this tax gradually in future years until it expires in 2010.
OTS Exh 2, Sched 8. Therefore, the ALJ opines that the pro forma amount in operating
expenses for CST should include the average book income and net worth for the five years
ending in 2005, excluding revenues from 2000, and should be calculated using the 5.99 millage
rate to be effective in January 2005, when the rates to be set here are also to go into effect
93
As a result of all the factors that he considered, OCA’s witness Morgan made a
total adjustment to the Company’s claim for taxes other than income resulting in a reduction of
$2, 527,000.00. OCA urges that the Commission adopt its recommendation. OCA MB at 42
The ALJ does not recommend that the Commission adopt this adjustment.
For all the reasons stated above, the ALJ recommends that the OTS adjustment to
the Company’s Capital Stock Tax calculation as set forth at OTS Exh 2, Sched 2 be accepted.
VIII.
1.
RATE OF RETURN
INTRODUCTION
From the Company’s point of view:
...this case is critical to PPL Electric’s financial future and
its ability to continue providing reliable service to its 1.3 million
customers in central and eastern Pennsylvania. Due to increasing
costs, a growing capital budget and lengthy rate caps, PPL
Electric’s financial condition has deteriorated significantly in
recent years to the point that it earned a return on common equity
of less than 2% in 2003, as compared to the 11.5% allowance
approved by the Commission in the Company’s last base rate
proceeding in 1995. As a result, PPL Electric’s current debt rating
is A minus, with a “negative outlook.” The Company almost
certainly will lose its weak A minus rating if it does not receive
adequate rate relief in this case. As recently stated by Standard &
Poor’s:
“The negative outlook reflects the still weak credit metrics
and the uncertainty surrounding the outcome of the rate case,
filed with the PUC in March, 2004. Although the company
expects new PUC rates to bolster its performance after 2004,
if new rates do not result in improvement in credit ratios, the
ratings on PPLEU (PPL Electric) will be lowered.” (PPL
Electric St. 9-R, p. 11).
This financial deterioration comes at a time when the
Company is facing significant capital requirements to replace and
upgrade an aging infrastructure. Specifically, the Company
anticipates that it will be required to invest approximately $900
million in capital improvements over the next five years.
94
Adequate rate relief is essential to the Company’s ability to attract
sufficient capital to finance these improvements and thereby
continue to provide reliable service to customers.
PPLEU MB at 3-4.
From OCA’s point of view,
...the Commission is considering PPL’s request, particularly its
request for an 11.5% return on equity, in an era when capital costs
have declined substantially since the Commission’s prior review of
this utility’s rates in 1994. Interest rates are quite low by historical
standards and inflation also remains low. In addition, recent
changes in the federal tax code have substantially lowered the
income tax rate on both capital gains and corporate dividends with
the dividend tax reduction being particularly dramatic. OCA St. 3
at 5-6.
The recognition of these factors defines the major difference
between the OCA and the Company in this proceeding. the OCA
and the Company differ substantially on the appropriate return on
equity, or profit for shareholders, in this restructured environment
for PPL’s distribution operations. Based on PPL’s risk profile and
current market data, the OCA recommends a return on equity of
9.5%, as compared to the Company’s request of 11.5%. The
Company’s overstated request, the same return on equity awarded
by the Commission to PPL nearly a decade earlier when it was a
vertically integrated utility, fails to account for these many changes
that have occurred over the past decade.
Indeed, the ratings agencies have recognized these factors:
FitchRating (July 11, 2003) states that its “ratings reflect the
low-risk nature of the company’s regulated distribution
operations and the absence of any near-term liquidity
concerns.” Moody’s (February 24, 2004) mentions that
PPLEU’s credit strengths are attributable to a “lower
business risk profile as a regulated transmission and
distribution utility.” Standard & Poor’s A-rating is
attributable to “its low-risk transmission and distribution
(T&D) electric operations, a large stable residential and
commercial customer base (78%), and a long-term power
supply contract (that runs from 2001 to 2009).” S&P goes
on to state that “ring-fencing” helps to insulate PPLEU from
unregulated risk but this insulation is not complete.
95
OCA St. 3 at 19-20. The OCA submits that PPL’s request
for an 11.5% return on equity simply fails to reflect the changes
that have occurred in Pennsylvania and current market conditions.
According to OCA, “PPL’s request significantly overstates PPL’s
cost of capital as a distribution utility.”
OCA MB at 3-4
For two other diametrically opposed view points, PPLEU argues that “the
unrebutted evidence in this case demonstrates PPL Electric’s overall management effectiveness
and efficiency”. PPLEU MB at 4. The fact that PPLEU’s president, John Sipics, submitted
prefiled testimony, attended the first day of hearings, and was available for cross-examination,
shows that the leadership of the Company backs the efforts put into this case, and the effort put
forward to having funds available to continue effective and efficient operations. On the other
hand, OCA asserts that PPLEU has done nothing spectacular, but has merely provided the
service that would be expected in circumstances like those facing many other electric utilities in
Pennsylvania.
The Company points to its “ability to provide reliable and efficient service at
reasonable rates”, while under a rate cap and facing a deteriorating rate of return. It goes on to
assert that “The Company’s rates are essentially the same as they were in 1986 and remain well
below national, Pennsylvania and regional averages”. It has won many service awards for
quality of service and customer satisfaction, cut costs, improved efficiency, and has not
sacrificed the quality of service to its customers. At the same time it has invested in substantial
system enhancements, including for example, a $160 million investment in a forward-looking
Automated Meter Reading (AMR) system. Now,
“it is critical that the Company receive adequate rate relief to
restore its financial health and prevent a further downgrading of its
debt ratings. In determining the amount of the increase, and in
particular, the common equity allowance, PPL Electric respectfully
requests that the Commission fully consider the importance of this
proceeding to the utility industry and the Commonwealth, PPL
Electric’s critical need for substantial rate relief and the
Company’s exemplary management performance.”
PPLEU MB at 4
96
2.
DISCUSSION
The Commission has ruled, and all parties in this case that are litigating this
issue11 agree that a public utility is entitled to an opportunity to earn a fair rate of return on the
value of its property which is dedicated to public service. Pennsylvania Gas & Water Company
v. Pennsylvania Public Utility Commission, 341 A.2d 239 (Pa. Cmwlth. 1975). This is
consistent with longstanding decisions by the United States Supreme Court, including Bluefield
Water Works and Improvement Company v. Public Service Commission of West Virginia, 262
U.S. 679, 690-93 (1923) (Bluefield), and Federal Power Commission v. Hope Natural Gas
Company, 320 U.S. 591 (1944) (Hope). The Commission in other cases and the parties that are
litigating this issue in this case all rely on or quote from the Bluefield case. In Bluefield the
Court stated:
[a] public utility is entitled to such rates as will permit it to earn
a return on the value of the property which it employs for the
convenience of the public equal to that generally being made at
the same time and in the same general part of the country on
investments in other business undertakings which are attended
by corresponding risks and uncertainties; but it has no
constitutional right to profits such as are realized or anticipated in
highly profitable enterprises or speculative ventures. The return
should be reasonably sufficient to assure confidence in the
financial soundness of the utility and should be adequate, under
efficient and economical management, to maintain and support its
credit and enable it to raise the money necessary for the proper
discharge of its public duties. A rate of return may be too high or
too low by changes affecting opportunities for investment, the
money market and business conditions generally.
(Emphasis added) Bluefield at 692-3; OTS MB at 44. See also, Pa.P.U.C., et al. v. Pennsylvania
American Water Company, Docket No. R-00038304 (Order entered January 29, 2004); Pa.P.U.C
v. Aqua Pennsylvania, Inc.; R-00038805, et seq. (Order entered August 5, 2004); PPLEU MB at
65-66; OCA MB at 45-46; OTS MB at 43-44; US DOD at 7-8.
11
The only parties that are litigating this issue are PPLEU, OTS, OCS and US DOD. PPLICA and
CAC adopt and support the OCA’s analysis.
97
The Commission also often cites a well-know authority in utility rate regulation
for its definition of a utility’s rate of return:
[t]he rate of return is the amount of money a utility earns, over and
above operating expenses, depreciation expense and taxes,
expressed as a percentage of the legally established net valuation
of utility property, the rate base. Included in the ‘return’ is interest
on long-term debt, dividends on preferred stock, and earnings on
common stock equity. In other words, the return is that money
earned from operations which is available for distribution among
the capital. In the case of common stockholders, part of their share
may be retained as surplus. The rate-of-return concept merely
converts the dollars earned on the rate base into a percentage
figure, thus making the item more easily comparable with that in
other companies or industries.
(P. Garfield and W. Lovejoy, Public Utility Economics, (1964), at 116).
However, OCA emphasizes that, as a general rule, a utility is entitled to no more
than a reasonable opportunity to earn a fair rate of return on shareholder investment. City of
Pittsburgh v. Pa. P.U.C., 126 A.2d 777, 785 (Pa. Super. 1956) (City of Pittsburgh II); OCA MB
at 48. OTS seems to agree with this standard. OCA MB at 45; OTS MB at 43
In determining a fair rate of return for a company, the Commission has
traditionally considered the utility’s capital structure in conjunction with its costs of debt,
preferred stock, and common equity. While there is no dispute as to the former matters, there is
a dispute here about capital structure:
3.
CAPITAL STRUCTURE
The following OCA table summarizes the capital structure proposals of the
parties:
98
TABLE A
Capital Type
Short-term Debt
Long-term Debt
Preferred Stock
Common Equity
Total
PPLEU12
(%)
0.00
51.30
1.83
46.87
100.00
OCA13
(%)
0.00
51.59
1.85
46.56
100.00
OTS14
(%)
0.00
51.30
1.83
46.87
100.00
OCA MB at 48; Footnotes from the original below
US DOD does not take a position on capital structure.
OTS opines that “A capital structure used for rate-making purposes must balance
the interests of both ratepayers and investors.” OTS MB at 44. OTS accepts PPLEU’S proposed
capital structure “for the purpose of establishing an appropriate return in this proceeding as it is
similar to industry averages”. OTS cautions that this does not mean that it endorses this capital
structure or that it agrees that it is the most efficient capital structure, or that it would warrant an
“A” rating by Standard & Poor’s. OTS MB at 44-45.
The OCA’s recommended capital structure varies slightly from that proposed by
the Company because OCA contests Witness Moul’s adjustment to the Company’s capital
structure. Specifically the OCA submits that the Commission should reject Moul’s adjustment to
the Company’s estimated 2004 year-end retained earnings. OCA, which has proposed inclusion
of short term debt in capital structure in other cases, accepts the exclusion of short term debt for
purposes of this proceeding. OCA avers that PPLEU makes modest intermittent use of short
term debt, and accepts its exclusion from the capital structure so long as PPL’s short term debt is
used in the calculation of the AFUDC rate instead. OCA MB at 50; OCA St 3 at 12.
12
13
14
PPL St. 9, Exh. PRM-1, Sch. 1.
OCA St. 3, Sch. MIK-1 at 1.
OTS St. 1, Exh. 1, Sch.1.
99
OCA contends that retained earnings are unlikely to exist at the end of this year
because there have been none for the past two years. OCA further argues that the projection of
their existence is unverifiable because PPLEU will pay its dividends to its parent after the close
of the test year.
PPLEU argues to the contrary that the amount of retained earnings, $34 million, is
already much larger than it was at this time last year, and that retained earnings have been
amassed because of construction planned for next year. PPLEU also contends that retained
earnings would have been higher in 2003 except that “The record demonstrates that PPLEU had
$8.8 million in employee severance costs in 2003, related to installation of the AMR system.
PPLEU St. 4, at 12-17; PPLEU 4-R, at 40-42. But for these costs, PPLEU contends it would
have had positive retained earnings.” PPLEU RB at 27
When setting rates, the Commission reviews a kind of accounting snap-shot of the
utilities’ financial picture, and sets rates that will be applied for some time into the future until
they are subsequently changed. That is why there are various techniques to smooth out the
impact of certain costs or revenue impacts such as amortization of unexpected repair costs and
weather normalization.
The question for the Commission is not only whether there will be the amount of
retained earnings at the end of 2004 that PPLEU claims, but whether this amount of year-end
retained earnings is likely to continue over the lifetime of these rates. Although PPLEU does
project large construction budgets over the next five years, it is not at all clear that the Company
will be able to build up or retain a high level of retained earnings, or indeed, whether it will want
to do so. After balancing PPLEU’S claim and OCA’s analysis, the ALJ recommends adoption of
the capital structure proposed by OCA, minus PPLEU’s proposed amount for retained earnings.
100
4.
COST OF DEBT AND COST OF PREFERRED STOCK
PPLEU’s proposed cost rates for preferred stock of 6.43% and for long-term debt
of 6.19% are included at PPLEU Exh PRM 1 at 1. No party contests these rates, and the ALJ
recommends that the Commission accept them. E. g., OCA T 3 at 14.
5.
RETURN ON COMMON EQUITY (ROE)
Four witnesses presented return on common equity (ROE) analyses in this
proceeding: Paul R. Moul for PPLEU (Moul), Kenneth L. Kincel for US DOD (Kincel),
Matthew I. Kahal for OCA (Kahal) and Kevan L. Deardorff for OTS (Deardorff). They each
used different methods, or different components to the same methods, and produced differing
results.
PPLEU Witness Moul provides analyses under the discounted cash flow (DCF),
Comparable Earnings (C/E), Risk Premium (R/P), and Capital Asset Pricing Model (CAPM).
US DOD witness Kincel performed DCF, R/P and CAPM analyses. OCA witness Kahal
performed a DCF analysis, and used a CAPM analysis to check it. OTS witness Deardorff
performed only a DCF analysis. Because, as discussed below, the Commission has relied on the
DCF method and the use of informed judgment, the ALJ will focus primarily on the various DCF
calculations and the elements of the formula. She will also look at the CAPM method which is
used as a check by OCA, and is occasionally used for this purpose by the Commission. She will
also discuss in passing the C/E and R/P methods as used by PPLEU and the reasons why OTS
finds them unreliable.
The ROE model test results and recommendations of the various parties are
summarized in the US DOD table and footnotes below (Table B)15:
15
The ALJ found the Main Brief of US DOD very helpful in preparing this section of the R.D., and
often relied on it, hopefully with attribution where necessary.
101
TABLE B
DCF
PPL
16
DOD17
OCA18
OTS19
RP
Comparable Reasonable
Point
Earnings
Range
Recommendation
CAPM
10.69%(E) 11.75% 10.71% (E)
to
(E &
to
11.22%(NG)
NG)
11.22%(NG)
9.3% to
10.44%
11.00%
10.26%
8.5% to
None 9.1% to 10%
9.5%
8.76% to
None
None
9.07%
14.25%
None
None
None
11.0% to
11.75%
10.25% to
11.0%
8.5% to
9.5%
8.75% to
9.0%
11.50%
10.75%
9.5%
9.0%
Note: For PPL: (E) means used electric utility comparable group; NG means used natural gas
utility comparable group. The other 3 witnesses used only electric utilities as a basis of
comparison.
Footnotes below, and Note from the original
US DOD MB at 9
As US DOD explains:
The major causes of the differences in Table B are: (1) the
choice of utilities for the comparable utility group(s); (2) selection
of the basis for the growth rate when applying the DCF model test;
(3) whether model test results are adjusted for “leverage;” (4)
whether a firm size adjustment was applied to the CAPM/ROE
estimate; and (5) whether the DCF model test results were relied
upon principally, or many model test results were used when
deriving the point ROE recommendation.
US DOD MB at 8.
16
17
18
19
PPL Statement No. 9, Direct Testimony of Paul R. Moul, at 5.
DOD Statement No. 2, Direct Testimony of Kenneth L. Kincel, Exhibit KLK-4, at 15, lines 7 to
24 for CAPM result. Admitted Transcript of August 11 and 12, 2004.
OCA Statement No. 3, Direct Testimony of Mathew I. Kahal at 30, 32.
OTS Statement No. 1SR, Surrebuttal Testimony of Kevan L. Deardorff at 2, lines 5-9.
102
A.
Use of Natural Gas Barometer Groups
The use of barometer groups in rate of return analysis is a way to meet the
standard that utilities are “entitled to such rates that will allow them to earn a return equal to that
generally being made at the same time and in the same general part of the country on
investments in other business undertakings which are attended by corresponding risks and
uncertainties.” Bluefield at 262 U.S. 679 (1923), at 692-693; Accord, Hope. The ALJ notes that
as always, there are variations in the barometer groups used by the various witnesses. In this
case, the variations among the electric barometer groups are not as controversial as is the use of a
natural gas barometer group by PPLEU.
PPLEU witness Moul developed an electric barometer group, but also used a
second barometer group comprised of natural gas utilities. He did so to try to eliminate a
problem he calls “circularity”, which he considers to be a second (the first being that unadjusted
DCF cost rate understates investor expected return rate) significant problem with the DCF
model. Moul explains this problem as follows:
Among other limitations of the model, there is a certain element of
circularity in the DCF method when applied in rate cases. This is
because investors’ expectations for the future depend upon
regulatory decisions. In turn, when regulators depend upon the
DCF model to set the cost of equity, they rely upon investor
expectations, which include an assessment of how regulators will
decide rate cases. Due to this circularity, the DCF model may not
fully reflect the rate of return necessary to compensate the utility
for the risks that are developing.
PPLEU St., 9 at 25; PPLEU MB at 75-76
PPLEU argues that “circularity” is a particularly important problem in this case
because “there is...great uncertainty about future growth rates following electric restructuring and
expiration of the rate caps. Investors are attempting to estimate what the commissions will do
while commissions are trying to estimate what investors require. Hence, the circularity inherent
103
in the DCF is particularly acute under current circumstances of the electric distribution
businesses.” PPLEU MB at 76-77
PPLEU’s witness Moul performed a preliminary DCF analysis for his barometer
group of electric distribution companies using the six month average dividend yield of 4.61%,
adjusted to 4.75% to reflect expected dividend growth, and an investor expected growth rate,
based upon analysts projections of earnings growth of 5.5%. The resulting unadjusted DCF cost
rate for the electric distribution groups is as follows:
Dividend Yield
4.75%
+
Growth
=
ROE
+
5.5%
=
10.25%
PPLEU St. 9 at 26-34; PPLEU MB at 77-78
Mr. Moul then adjusted the DCF cost rate to include a “leverage” adjustment.
The resulting DCF cost rate for the electric distribution group is as follows:
Dividend Yield +
4.75%
+
Growth
5.5%
+ Leverage Adjustment
= ROE
+
= 10.69%
0.44%
Moul reasoned that while this adjustment corrects for the understatement of the
allowed ROE by the DCF analysis resulting from market prices exceeding book value, it does
nothing to address concerns about “circularity” of the DCF analysis. Mr. Moul, therefore,
calculated a DCF cost rate for a group of gas distribution companies, because the gas industry
has had a deregulated stable supply market for many years. The resulting DCF cost of equity is
as follows:
Dividend Yield +
4.18%
+
Growth
6.25%
104
+ Leverage Adjustment
= ROE
+
= 11.22%
.79%
Neither Moul, nor PPLEU in its Briefs, has persuaded the ALJ that looking at
Moul’s gas industry DCF analysis does anything to break the “circularity” problem he perceives,
or indeed that “circularity “ is the problem that he says it is. Moul’s DCF for the gas industry is
indeed higher, but I see no reason to adjust the electric industry results on that basis. PPLEU
argues, without supporting evidence, that the natural gas industry has already completed the
transition from regulation to deregulation and is now a stable industry. PPLEU MB at 78-79.
Moul tries to argue that investors might consider the gas industry as similar to the
electric industry, arguing that there are many parallels. Id. Nonetheless, the DCF analysis for
that industry must be just as circular as that for the electric industry. If PPLEU is correct, then it
may be a sound projection that someday the electric industry will reach this status also, but one
would not project the same rate of return in the present for the two industries on this basis.
PPLEU argues that “Other parties have attempted to dismiss the gas DCF as
unrelated to the electric distribution business, but have not attempted to explain how to avoid the
circularity of the DCF analysis, particularly in this period of transition for electric distribution
companies.” Id. This is true on both counts, but neither has Moul explained in a satisfactory
way the true existence of circularity, or a technique to avoid the circularity problem, and it is his
issue and his burden of proof.
PPLEU reviews US DOD witness Kincel’s DCF analysis favorably, with some
criticism about the lack of an arithmetically calculated leverage adjustment, and concludes that
“Kincel must be commended for recognizing and attempting to adjust for the deficiencies of the
DCF analysis”. PPLEU MB at 80. However, US DOD does not agree with Moul on use of the
gas industry barometer group.
US DOD argues that “The Company’s use of a “Natural Gas Utility Comparable
Group,” in addition to an Electric Utility Comparable Group was particularly significant in
setting the high side of Moul’s ROE estimates from the DCF and CAPM models, as designated
105
by “NG” in Table B, supra.” US DOD MB at 9. Kincel rejected use of natural gas utilities in
the ROE analysis for the following reasons as stated in his direct testimony:20
I did not use Mr. Moul’s Natural Gas Group, because,
despite similar cost-based regulation, I believe natural gas utilities
are not sufficiently similar to electric utilities that an investor will
seek the same ROE for both. Natural Gas utilities face different
market risks and opportunities than electric utilities, deliver a very
different commodity which can be used in applications that
electricity cannot, and enjoy a deregulated environment for its
commodity that is more well-established and stable throughout the
country.
Id.
OCA Witness Kahal rejects use of the “Natural Gas Group” stating that “The gas
proxy group is clearly irrelevant to this case and should be disregarded entirely.” OCA St 3 at 7.
Kahal believes that the gas proxy group is inappropriate as a risk proxy for PPLEU’s electric
operations because the gas industry is not comparable to the electric industry. Id. at 10; OCA
MB at 75. He adds that it could provide misleading results. Id. at 27. Deardorff simply chose
not to use a “Natural Gas Comparable Group” for his ROE analysis. On Brief, OTS rejects the
use of a Natural Gas Barometer Group: “Reliance on the gas industry is misguided and serves
only as an attempt to justify an excessive equity return request.” OTS RB at 28
For all the reasons stated by Kincel and Kahal and OTS, the ALJ recommends
that the Commission reject use of PPLEU’s ROE test results based on the natural gas utilities
barometer group, as designated by “NG” in Table B when determining the appropriate
authorized ROE for PPLEU in this proceeding.
20
US DOD Statement No. 2, Direct Testimony of K. L. Kincel for DOD, page 7, lines 1-7.
106
B.
DCF
The basic DCF formula is set forth below, translated into English, and arranged to
solve for the cost of equity:
Cost of equity = 1st year end Dividend
Current market price per share
Of stock
+
growth rate
Principles of Public Utility Rates, Bonbright, Danielsen, Kamerschen (Public Utilities Reports,
Inc.1988) at 317-32221. This formula is intended to capture what investors expect the market
rate to be. Obviously, the key factor in this formula is the growth rate, although all the variables
are important. The experts in this case differ most about the growth rate.
PPL presented the testimony of Paul R. Moul to support its rate of return request.
The following summarizes the Company’s request:
Capital Type
Long-term Debt
Preferred Stock
Common Equity
Total
Percent of Total
(%)
51.30
1.83
46.87
100
Cost Rate
(%)
6.43
6.19
11.50
Weighted Cost
(%)
3.30
0.11
5.39
8.80
PPL St. 9, Exh. PRM-1, Sch. 1. OCA and OTS opine that, in particular, the Company’s 11.50
percent cost of common equity request is well in excess of an objective assessment of investor
market requirements. US DOD also asserts that this growth figure is too high.
The correct mathematically stated formula may be found in witness Deardorff’s testimony: “My
analysis employs the standard discrete DCF model, k = D1/P0 + g, where D1 is the dividend expected during the
year, P0 is the current price of the stock, and g is the expected growth rate of dividends. For purposes of calculating
a dividend yield applicable to the formula, D0/P0 (the current dividend divided by the current price) must be
adjusted by ½ the expected growth rate in order to account for changes in the dividend rate in period 1.”
21
107
OCA presents the testimony of Matthew I. Kahal to support its rate of return
allowance. The recommendation of the OCA is as follows:
Capital Type
Long-term Debt
Preferred Stock
Common Equity
Total
Percent of Total
(%)
51.59
1.85
46.56
100
Cost Rate
(%)
6.43
6.19
9.50
Weighted Cost
(%)
3.32
0.11
4.42
7.85
OCA St. 3, Sch. MIK-1 at 1.
OTS presents the testimony of Kevan L. Deardorff to support its rate of return
recommendation. The recommendation of the OTS is as follows:
Capital Type
Long-term Debt
Preferred Stock
Common Equity
Total
Percent of Total
(%)
51.30
1.83
46.87
100
Cost Rate
(%)
6.43
6.19
9.00
Weighted Cost
(%)
3.30
0.11
4.22
7.63
OTS Exh. No. 1-SR, Sch.1.
The U S Department of Defense (OS DOD) presents the testimony of Kenneth L.
Kincel to support its rate of return recommendation. The recommendation of US DOD is as
follows:
Capital Type
Long-term Debt
Preferred Stock
Common Equity
Total
Percent of Total
(%)
51.30
1.83
46.87
100
Cost Rate
(%)
6.43
6.19
10.75
108
Weighted Cost
(%)
3.30
0.11
5.03
8.44
US DOD Kincel Dir. at 5. This table originally had only US DOD’s equity cost rate, and the
ALJ filled in the blanks with the capital structure proposed by PPLEU and agreed by OTS, and
the other uncontested cost rates.
Witness Kincel also attempted in his DCF analysis to recognize at least some of
the perceived inherent deficiencies in the DCF analysis. He is the only witness that appeared to
have a realistic view of the DCF method’s shortcomings, and to have a reasonable response to
them. After having arrived at a range of DCF results from 9.3% to 10.26%, DOD St. K. Kincel,
at 10,22 (Footnote included below), Kincel adopted the top end of his DCF range as his DCF
result noting as follows:
“When the price-to-book value ratio of a stock is greater than 1.0,
the DCF test result using the constant growth model tends to be
less reliable (i.e., a greater probability of error). This occurs
because it becomes less possible for the key assumption underlying
that model to be realistic, that is, that the growth in earnings,
dividends and book value can be approximately the same in the
future. Under these circumstances, the estimate of ROE produced
by the DCF model can be expected to be lower than the expected
ROE because an investor purchasing the stock is undertaking a
greater risk that the price will actually decline in the near future to
approach book value.”
DOD St. 2 at 14.
Kincel did not apply a mathematical formula to adjust the results of his DCF
analysis as proposed by Moul, but he did exercise his judgment to adopt the high end of the DCF
range-10.26, which he then rounded to 10.25. This is consistent with the Commission’s practice
to slightly augment DCF results when the market price substantially exceeds book value. The
Company contends, without basis, that this is arguably an incomplete adjustment because even
the unadjusted high end of Mr. Kincel’s DCF range understates the equity cost rate.
22
The 9.3% result reflects averaging of projected growth in earnings, book value and dividends and
the 10.26% uses only projected dividends. The latter may be more appropriate given uncertainties of future earnings
growth in the current circumstances.
109
Kincel also performed Risk Premium and a CAPM analysis for his final
recommendation. He combined these with his DCF result to reach his overall result of 10.75.
C.
The Electric Barometer Groups
The OCA, OTS, US DOD and PPLEU have identified similar electric barometer
groups. The following table presents these groups for comparison23 (Footnote included below):
TABLE C
Company
US DOD
OCA
OTS
PPL
CH Energy Group
Central Vermont Public Service
Consolidated Edison
Duquesne Light Holdings
Energy East Corp
Green Mountain Power
Northeast Utilities
NSTAR
Pepco Holdings, Inc.
UIL
X
X
X
X
X
X
X
X
X
X
X
X
Xp*
Xp*
Xp*
X
Xp*
Xp*
Xp*
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
* - Xp indicates the OTS primary group; OTS also considered the full nine-company group in its
analysis
OCA MB at 76
PPLEU contends that OTS’s and OCA’s reliance either solely or primarily on the
DCF model must be rejected because it ignores precedent. PPLEU gives no citation for this
precedent, perhaps because there is none. In the last PP&L rate case, about 10 years ago 24, the
23
OCA argues that given that these groups are so closely matched, Kahal is correct that a gas
industry proxy group is simply unnecessary here. Moul’s gas group is too risky for comparison to an electric
distribution company; it would be unwise to use potentially misleading data when there are sufficient electric
utilities in the proxy groups. The ALJ agrees.
24
As a matter of historical interest, Paul Moul and Matthew Kahal were the rate of
return witnesses for PP&L and OCA in that case also. Kevan Deardorff and Kenneth Kincel
were not mentioned.
110
Commission relied entirely on the DCF method: “...we conclude that there is no reason for us to
divert from our practice of considering the DCF method exclusively for equity rate of return
determinations.” PaPUC et al v Pennsylvania Power and Light Company, 85 PUC 306, 388
(1995).
Coming forward about 10 years, in two almost contemporaneous recent decisions,
the Commission relies primarily on the DCF method, while looking to other factors as a check,
or for adjustments if justified. PaPUC v Aqua Pennsylvania, Inc., Docket No. R-00038805
(Order entered August 5, 2004) (Aqua Pa) (“We have often relied on the DCF methodology and
informed judgment in arriving at our determination of the proper cost of common equity...”; in
this case, the Commission did consider other factors which it found to affect the cost of capital)
Slip Opinion at 61-65; PaPUC v Pennsylvania-American Water Company, Docket No.
R-00038304 (Order entered January 29, 2004) (Pa American) (“We determine that the DCF
method is the preferred method of analysis to determine a market based common equity cost
rate.”) Slip Opinion at 83 (Emphasis added).
In Pa American, the Commission agreed with the ALJ’s adoption of a market
based common equity cost rate based on the DCF method as a starting point, but it also found
merit in the financial risk adjustment (leverage) proposed by the Company saying:
We note that, in Lower Paxton Township v. Pennsylvania Public
Utility Commission, 317 A.2d 917 (Pa. Cmwlth. 1974) (Lower
Paxton Township), the Commonwealth Court recognized that this
Commission may consider such factors that affect the cost of
capital such as the utility’s financial structure, credit standing,
dividends, risks, regulatory lag, wasting assets and any peculiar
features of the utility involved.
Id. at 83-84; Accord, Aqua Pa, Slip Opinion at 61-66. The ALJ had recommended 10.0%, and
the Commission, based on a leverage adjustment, raised it 60 basis points to 10.60%. The
Commission rejected a higher leverage claim from Pa American. The ALJ, and also the
111
Commission did not accept a Company claim to a higher cost of equity rate based on its
management performance. Slip Opinion at 84-85
In Aqua Pa, the Commission opined that the DCF result should have been
checked with other financial models for reasonableness, should have been checked against the
most recent available data, that the increase in corporate bond yield should have been
recognized, that a leverage adjustment was appropriate, and that the Company had shown quality
management performance in various areas including taking over NUI and providing better
quality service to its customers. Slip Opinion at 62-65. Based on all of this, the Commission
raised the ALJ’s recommended DCF-based, cost-of-equity rate of 10.0% to 10.60%.
Here, PPLEU ‘s President, John F. Sipics, testified that the Company’s
commitment to the highest quality service has never diminished, and presented results:
(1)
(2)
(3)
(4)
PPLEU has met or exceeded reliability standards as
measured by the Customer Average Interruption Index, the
System Average Interruption Index and System Average
Interruption Frequency Index in all but one year of the rate
cap period;
PPLEU focuses on the few instances where the indices
decline and implements appropriate initiatives to improve
performance;
PPLEU has received numerous JD Power and Associates
awards for customer satisfaction and was ranked highest in
the nation for combined electric and gas utilities in 2001,
2002 and 2003; and
Eighty eight percent of customers rank PPLEU as an above
average service provider and customers rank PPLEU 8.3 on
a scale on a scale of 1 to 10 on overall satisfaction with 10
being “outstanding”.
PPLEU St. 1, pp. 5-6; PPLEU MB at 68
PPLEU continues its quality assertions by further relying on Sipics thus:
112
It is not surprising that PPLEU is highly regarded by its
customers. It has continued its commitment to service during the
rate cap period despite a return on equity of less 2% in 2003.
Furthermore, PPLEU’s total bills to customers are about the same
today as they were 18 years ago. PPLEU has been able to maintain
service without rate increases to customers by aggressive
management of costs.
PPLEU St. 1 at 3 and at 6-7; Id.
PPLEU does not argue that it should be allowed an increment above the cost of
capital as defined by Hope and Bluefield. It argues instead that the Commission should reflect its
approval of PPL’s practices in selecting the range of reasonableness, preferably witness Moul’s
range of 11.0% to 11.75%, and in selecting the point in the range.
The ALJ concludes that the Commission wants to receive for review the most
correct DCF result produced on the evidence before it, and separately identified recommended
adjustments, which it will apply if it finds it appropriate to do so. The ALJ does not read Pa
American and Aqua Pa to hold that the DCF result should be adjusted automatically and
inclusively by the ALJ to a cost rate that one or more parties argue to be desirable and correct, or
that the cost of equity should be a composite of the DCF and other methods such as R/P or
CAPM. Clearly, there is enough information here if the Commission wants to include quality of
management as a factor in the determination of ROE.
D.
CAPM
Witnesses Moul, Kincel, and Kahal performed a CAPM analysis, producing, of
course, different results. Kincel’s CAPM ROE result was 11.00%. Moul came up with a range
of 10.71% (E) to 11.22% (G). Both Moul and Kincel used the small company adjustment of
0.82% recommended by Ibbotson Associates when employing the traditional CAPM model.
Kahal, who produced 9.1% to 10.00%, rejects use of the “size” adjustment because it is the much
larger parent company that will be issuing the stock. Kincel finds this irrelevant because it is the
smaller subsidiary for which results are being sought, and points out that if the size adjustment
113
were applied to Kahal’s results, they would be in the range of his and Moul’s results. US DOD
MB at 13. In any event, Kahal concluded that his unadjusted CAPM result confirmed or
supported his DCF result of 8.5% to 9.5%.
The ALJ opines that the small firm adjustment is not central to this issue because
the Commission will only be using CAPM results as a check on the DCF results. However, she
opines that OCA’s position has merit because PPLEU is not in any way a stand alone firm, and
does not come before the Commission as an isolated company, and probably does not fit easily
into any “certain size group”. PPLEU is a part of an articulated corporate structure, a subsidiary
of PPL Corp, dependent on its relationships to a number of other subsidiaries within the
corporate family. In fact some of these relationships reduce its riskiness, viz., its full
requirements supply contract through the remainder of this decade with its corporate affiliate,
PPL Energy Plus. Therefore, the ALJ would consider the small firm adjustment to be
unnecessary. In any event this is an adjustment that applies to a secondary method used to
checkout the DCF result.
E.
Comparable Earnings
Witness Moul was the only analyst who performed a ROE analysis with this
method. He performed it on a group of companies which included unregulated companies in a
“broad and disparate group that is not adequately comparable to electric utilities.” US DOD MB
at 14. The other analysts rejected this method and Moul’s findings with it because of the
barometer group he used, which they did not consider to be comparable to the utility barometer
groups. Because of this, “the Commission should attach very little weight to the Company’s
very high ROE estimate derived by the Company using the Comparable Earnings methodology.”
US DOD argues that Moul appeared to give it very little weight himself. Id.
114
F.
“Wires Only” – More Or Less Risky?
The ALJ opines that it is very difficult at this point in time to assess whether
PPLEU is less risky as a wires only, delivery service utility. It seems well protected, tucked in
under PPL Corp with a number of other subsidiaries that are designed to and prepared to do
business with and for it. A prime example of this is its all-requirements contract for electric
supply with PPL Plus which runs until 2009. However, what will happen when the generation
cap comes off in 2009? It is unknown whether PPLEU still will be able to get an advantageous
contract with this same subsidiary.
Until then, PPLEU appears to be less risky than it was as a fully integrated utility
that owned its own generation.
G.
Leverage Adjustment
The Company contends through Moul and its lawyers that the Commission has
adopted the leverage adjustment, and that the Commission’s precedents show that the DCF
method is inadequate to measure market based rate of return, and that it must be adjusted. I
agree that in two recent cases, the Commission has made what Moul and the Company call a
leverage adjustment: Pennsylvania American and Aqua Pa. However, these adjustments,
particularly in Aqua Pa, had many other elements mixed in, including acknowledgement of
superior performance.
Here, all opponents argue that a leverage adjustment is inappropriate. US DOD
witness Kincel rejected the use of a leverage adjustment for the following reasons:
I do not agree with the use of the “Leverage Adjustment”
applied by Mr. Moul to both the DCF test and the betas used in the
CAPM model test for ROE. The prices of a stock over time, and
the statistical variance in the price of a stock as measured by the
beta, are a result of the combined estimates of the value of a
company by investors as determined by employing all the data and
information about the company that are available. Investors, at
115
least those that survive in the market, understand the greater risks
that are accompanied by greater leverage, and by a price level that
is higher than book value, and these risks are already reflected in
stock prices as they vary over time. There is no need for a further
adjustment, as if the market value of a stock was determined with
no recognition of its relationship to book value, the leverage of the
company, or the manner in which state commissions set ROE for
purposes of computing rates during regulatory treatment.
US DOD St 2 at 18; MB at 12. The federal agencies argue that both Kahal, OCA St 3 at 38-44
and Deardorff OTS St 1 at 25-27 agree with Kincel.
Indeed, OCA presents many arguments against the concept of the leverage
adjustment. OCA MB at 79-94. Primary among them is the fact that in its restructuring case,
because it received a large stranded cost recovery because it was determined that the market
value of its generation assets was less than their book value. Here, the Company has turned this
formula on its head to reach a similar result—a larger award. OCA MB at 88. OCA also argues
that the leverage adjustment is not necessary to support the Company’s credit rating.
OCA also shows that the adjustment is incorrectly calculated, and argues that it is
three to four times too large because Witness Moul mistakenly uses the market equity rate for
Witness Mouls’ proxy group rather than for PPLEU; that he erroneously omits short-term debt
and there is nothing in the Miller Modigliani leverage formulation that permits this omission.
OCA MB at 89. OTS also finds that the adjustment is incorrectly calculated.
In agreement with OTS and US DOD, OCA argues that the DCF methodology
captures the investors reaction to this market to book ratio, and no extra adjustment needs to be
made. OCA MB at 84-88; OTS MB at 55-56.
The ALJ acknowledges that the Commission has made this adjustment in
different amounts in two recent cases, but she recommends that it not be used here, as is
discussed below.
116
H.
Summary and Conclusions
PPLEU witness Moul based his analysis in part on a nine-member electric group
that had five common characteristics. All parties used the same basic Comparable Electric
Group with some variations.
Mr. Kincel dropped CH Energy because its ROE was less than the
cost of utility debt. Mr. Kahal dropped Central Vermont and Green
Mountain because they were located in Vermont, a state without
retail customer choice, and added United Illumination despite
uncertainty over its dividend as reported by Value Line. Mr.
Deardorff performed his DCF analysis with all 9 companies
chosen by Mr. Moul, then with a group that eliminated 3 that did
[not] have at least 2 sources of earnings forecasts. Mr. Deardorff
was the only analyst that also applied the DCF analysis to PPL, the
parent company, itself.
US DOD MB at 9, Fn. 33.
US DOD maintains that small additions and deletions of individual companies to
the Comparable Electric Group explain only a small part of the differences shown in Table B.
The choice of the appropriate growth rate for use within the DCF analysis was a
primary source of the differences shown in the first column of the above table. For his Electric
Utility Group, Witness Moul employed a growth rate of 5.5% based primarily on earnings
forecasts. Witness Kahal chose a growth rate range of 3.5% to 4.5% based on a variety of
earnings forecast sources. Mr. Deardorff also chose forecast earnings growth as a basis of his
growth rates of 4.03% for its 9 member Electric Group, 4.13% for its 6 member Electric Group
and 5.13% for PPL, itself.
In contrast, Mr. Kincel developed a range of DCF model test results using average
earnings, book value and dividend growth of 4.58% for the lower end, and 5.5%
based on dividend growth for the upper boundary. These two growth rates are
used in the DCF calculation to define the range of 9.3% to 10.26% for DCF
model test results. Later in his testimony, Mr. Kincel chose the 10.26% (rounded
to 10.25%) dividend growth-based ROE as the most realistic estimate because: (1)
117
the DCF analysis tends to produce low estimates of ROE when the price-to-book
ratio is greater than 1.0, as it is for this Comparable Group (1.49); (2) the original
DCF computation is based on dividend growth before simplification into the
single stage growth model; and (3) in Mr. Kincel’s judgment “there is nothing
better than hard cash dividends to provide a realistic estimate of the growth rate,
and the associated ROE, for a group of utilities.” DOD supports the reasoning of
Mr. Kincel, and recommends that the Commission consider as the most realistic
estimate of ROE stemming solely from DCF analysis to be 10.25%.
US DOD MB at 11-12.
The ALJ points out that both Deardorff’s and Kahal’s DCF results when used in
the appropriate formulas are shown to provide all the creditworthiness required. Kahal has
“shown that his 9.5 % ROE, in combination with the book capital structure, produces very
acceptable financial ratios (i.e., interest coverage, debt ratio, cash flow measures).” OCA St 3 at
43; OCA MB at 88.
US DOD describes Moul’s use of a leverage adjustment as follows, and finds it
flawed:
The Commission should find Mr. Moul’s estimates of ROE
from his DCF and CAPM analysis (shown in Table B) to be
unrealistically high because of his use of an erroneous “leverage”
adjustment.” Mr. Moul believes that the cost of equity determined
by market analysis must be adjusted to book value, an adjustment
that increases the ROE to be applied in rate proceedings.25 Using
this adjustment, he increases his DCF-based ROE estimate for the
Electric Group by 0.44%, from 10.25% to 10.69%. He applies a
similar “leverage” adjustment to the betas used in his CAPM
analysis, thereby artificially increasing his ROE estimate for the
Electric Group by 0.4%, from 10.31% to 10.71%.
DOD Statement No. 2 at 18. (Footnote included above)
DOD Witness Kincel rejected use of a leverage adjustment for the following
reasons:
25
PPL Statement No. 9 at 35-37.
118
I do not agree with the use of the “Leverage Adjustment”
applied by Mr. Moul to both the DCF test and the betas used in the
CAPM model test for ROE. The prices of a stock over time, and
the statistical variance in the price of a stock as measured by the
beta, are a result of the combined estimates of the value of a
company by investors as determined by employing all the data and
information about the company that are available. Investors, at
least those that survive in the market, understand the greater risks
that are accompanied by greater leverage, and by a price level that
is higher than book value, and these risks are already reflected in
stock prices as they vary over time. There is no need for a further
adjustment, as if the market value of a stock was determined with
no recognition of its relationship to book value, the leverage of the
company, or the manner in which state commissions set ROE for
purposes of computing rates during regulatory treatment.
OCA’s Kahal and OTS’s Deardorff agree with these reasons for rejection offered by US DOD’s
Kincel and add others.
The ALJ accepts the argument to reject the leverage adjustment to the CAPM
analysis because she accepts the rationale that such an adjustment is included in the multi-year
horizon examined in the CAPM methodology. However, a leverage adjustment for the DCF
methodology is a different matter, but according to all the opposing analysts in this case, it is
already included in the derived values. US DOD witness Kincel presented the most persuasive
comments on how and why his application of the DCF method corrected for the problems in the
method.
The ALJ rejects PPLEU’s contention, repeated many times and in many ways that
the Commission has adopted a new and different approach to cost of equity review. The
Commission relies on a 1974 Commonwealth decision, Lower Paxton Township v. Pennsylvania
Public Utility Commission, 317 A.2d 917 (Pa. Cmwlth. 1974) (Lower Paxton Township), to
support its rationale to include related factors in its DCF based decisions. In PA American, it
used only the market to book capitalization factor to adjust the DCF result, and stated that there
were no other bases for upward adjustment. In Aqua Pa, it reviewed a number of other factors to
119
bolster its adjustment to the basic DCF award. In this case, PPLEU’s circumstances appear to be
closer to those in PA American than to those in Aqua Pa.
The Commission has employed a version of this adjustment in two recent
decisions:
We are also persuaded by AP’s reasoning that a financial
risk adjustment is necessary to compensate it for the application of
a market based cost of common equity to a book value common
equity ratio. We note that preliminar[ily] the DCF calculation,
which is computed using the market price of AP’s common stock,
should be adjusted to reconcile the divergence between market and
book values. Additionally, when investors value a company’s
common stock, they employ actual market capitalization data, and
not book data, although book capitalization is employed for
ratemaking purposes.
Slip Opinion at 63. Accord, Pa American, Slip Opinion at 84; See Pa. P.U.C. v. PennsylvaniaAmerican Water Co., 2002 Pa. PUC LEXIS 1; Pa. P.U.C. v. Philadelphia Suburban Water Co.,
219 PUR 4th 272 (2002); Pa. P.U.C. v. Pennsylvania-American Water Co., 231 PUR 4th 277
(2004). Citations from MB)
PAWC indicates that a preliminary DCF calculation, which
is computed using the market price of PAWC’s common stock,
should be adjusted to reconcile the divergence between market and
book values. The indicated cost of common equity of 10 percent,
therefore, reflects the barometer group’s average market
capitalization, which includes a common equity ratio of 62 percent
as opposed to the recommended common equity ratio of 42.20
percent which reflects significantly more financial risk. PAWC
further indicates that, when investors value a company’s common
stock, they employ actual market capitalization data and not book
data although book capitalization is employed for ratemaking
purposes.
We agree that a financial risk adjustment is proper.
Accordingly, we find that, in order to place the computed DCF
result on a consistent basis with the greater financial risk, inherent
in PAWC’s book value-derived capital structure ratios, a 60 basis
120
point financial risk adjustment above our 10 percent representative
DCF common equity cost rate recommendation is warranted.
We further conclude that the record in this proceeding does
not support any further upward adjustments. Under the
circumstances, we find that the cost of common equity of 10.60
percent is reasonable, appropriate and in accord with the record
evidence.
Pa American, Slip Opinion at 83-85
As a result, the ALJ finds she must recommend application of a similar
adjustment here if either the OTS or the OCA method and result are adopted, because a similar
disparity exists between PPLEU’s actual market capitalization data and its book capitalization
used for ratemaking purposes. However, US DOD’s DCF method and result seem to include
enough risk factors, or to reduce the disparity so as to produce a result that does not require
adjustment, viz., witness US DOD’s opinion that this adjustment is not necessary. Therefore, the
ALJ recommends adoption of US DOD’s unadjusted DCF result of 10.25%.
Moul and Kincel use all model test results to determine their reasonable range and
point estimates for authorized ROE in this case. The ALJ opines that the Commission rejects
this method in favor of relying on the basic DCF method as adjusted when circumstances
indicate that judgment should be applied. Both Kahal and Deardorff rely heavily on the DCF
analysis to determine their ROE estimates. Deardorff directly rejects use of the CAPM and RP
methodologies as not useful because the distant past over which the risk premiums are calculated
may not be representative of the future. However, the Commission has stated that use of CAPM
results to check DCF results may be appropriate. All three opposing witnesses reject the use of
the Comparable Earnings test as applied by Moul, because it uses unregulated companies that
comprise a broad and disparate group that is not adequately comparable to electric utilities.
Based on the above summation, the Commission should attach very little weight
to the Company’s very high ROE estimate derived by the Company using the Comparable
Earnings methodology. Moul himself apparently gave it little weight when he derived his point
estimate of 11.5%. Because the Commission does not give almost equal weight to all three
121
methodologies, namely the DCF, RP and CAPM methodologies, the Commission should reject
Kincel’s overall recommended ROE of 10.75%. The Commission chooses to rely primarily on
the DCF methodology for determining ROE, therefore the ALJ recommends that the
Commission adopt an authorized ROE of 10.25%, the DCF result that witness Kincel felt was
comparatively realistic. Witness Kincel opined that a compensation for the market capitalization
to book capitalization disparity was included in his DCF methodology. PPLEU praises Kincel’s
approach and results, with the exception of his omission of a mathematical formula for including
a leverage amount. Neither OCA nor OTS has criticized his methodology. The ALJ finds that
this is the most appropriate DCF ROE result produced for this case. She declines to make a
leverage adjustment since Kincel states compensation for book to market disparity is included in
this result.
The rate of return recommendation of the ALJ, based on the OCA capital
structure is as follows:
Capital Type
Long-term Debt
Preferred Stock
Common Equity
Total
Percent of Total
(%)
51.59
1.85
46.56
100
IX.
Cost Rate
(%)
6.43
6.19
10.25
Weighted Cost
(%)
3.32
0.11
4.77
8.20
RATE STRUCTURE
PPLEU points out “several important ratemaking principles” to those parties
enthusiastically pursuing cost based allocations:
First, it is well-established that cost is only a guide in the
formulation of a rate structure. Pa. P.U.C. v. National Fuel Gas
Distribution Corp., 73 Pa. PUC 552, 621 (1990); Pa. P.U.C. v.
Equitable Gas Co., 73 PaPUC 301,347 (1990). Cost of service
allocations are one of the most subjective elements of rate
structure. The task of the Commission is not to select any
particular cost of service study as correct. Cost of service studies
122
are to be used in conjunction with other factors such as gradualism
to allocate revenue requirement. Pa. P.U.C. v. West Penn Power
Co., 73 Pa. PUC 452, 516-18 (1990). The Commission has never
adopted class cost of service as the sole basis for allocating costs
among rate classes.
PPLEU MB at 101-102
Moreover, as stated by PPLEU, the Commission has repeatedly recognized that
the cost of service study is only a guide to designing rates and is only one factor, albeit an
important one, to be considered in the rate setting process. See, e.g., Pa. P.U.C. v. Pennsylvania
Power & Light Co., 55 PUR 4th 185, 249 (1983) (describing cost of service study as “a useful
tool” for testing reasonableness of a proposed allocation). Moreover, cost of service analysis is
not an exact science, and there is no single, absolutely correct method. See id. (describing cost
of service study as “engineering art”); PPL Electric St. 5-R at 2.
One of the primary court precedents supporting Commission flexibility on these
issues is U.S. Steel Corp. v. Pa. P.U.C., 37 Pa. Commonwealth Ct. 173, 185, 390 A. 2d 865
(1978). There the Court affirmed a Commission Order exempting the first 500 KWH of
residential usage from a PECO rate increase. The Court concluded that the Commission’s action
was “a proper exercise of the Commission’s flexible limit of judgment in fixing rates.” Indeed,
paraphrasing the opinion of the Court, there is no reason why the Commission must follow
principles of cost causation rigidly. The Court in U.S. Steel explained as follows:
… Certainly there is nothing in Pennsylvania law which now
empowers the Commission to require one customer simply to pay
another's utility bill; and, as we have mentioned, the utility may not
and could not for long be required to provide such subsidy out of
its capital. This is not to say, however, that rate structures may not
be rearranged from time to time in response to changes in
economic conditions -- whether general changes or changes
especially affecting particular classes of customers. The law
presently permits reduced rates to large industrial and commercial
consumers, either because such customers buy a lot of what the
utility provides or because they may use another's product if the
price factor warrants. Pittsburgh v. Pennsylvania Public Utility
123
Commission, 182 Pa. Superior Ct. 376, 126 A.2d 777 (1956). We
see no reason why in times of stringency the utility might not
propose, and the Commission might not approve, rates for
residential users less than the rates which an allocation of large
increases in necessary revenues by a strict application of cost of
service studies would suggest.
U.S. Steel Corp. v. Pa. P.U.C., 37 Pa. Commonwealth Ct. 173, 185, 390 A. 2d 865 (1978).
1.
RATE STRUCTURE - TRANSMISSION SERVICE CHARGE
At the same time that PPLEU proposes to increase its distribution rates, the
Company proposes to pass through to customers a projected increase in charges for transmission
services that it purchases from the Pennsylvania-New Jersey-Maryland Interconnection, LLC
(PJM) in the amount of $57 million. (PPLEU St. 4 at 31). Total transmission charges to PPLEU
in the future test year are projected to be $198,973,679 PPLEU Ex. DAK3. PPLEU proposes to
recover these charges through a Transmission Service Charge (TSC) as set forth in its proposed
tariff supplement at pages 19Z – 19Z.1. Supplement No. 38 to PPLEU Tariff – Electric Pa.
P.U.C. No. 201, Ex. OGK1. PPLEU MB at 93
As proposed by the Company, initially the TSC would be $0.0564/kWh.
The following parties have taken a position on the TSC: OTS, OCA, OSBA,
PPLICA, CCC, US DOD and MAPSA. OSBA, PPLICA, US DOD and CCC on the whole
concentrated their efforts on changing the basis for the TSC from energy, i.e., cents/ kWh, to
demand. OTS opposed reconciliation. However, some parties, notably OCA and MAPSA,
support the Company’s proposal. Transmission revenues are expected to increase $57 million to
approximately $200 million, and this amount represents 29% of the Company’s distribution
revenues at the proposed rates of $688 million, PPLEU MB at 96. The TSC cannot be regarded
as a side issue.
Pursuant to the Electricity Generation Customer Choice and Competition Act,
(Customer Choice Act), 66 Pa.C.S. §§ 2801 et seq, as the statutory Provider of Last Resort
124
(POLR), PPLEU must provide generation services for retail customers who do not shop for those
services. In order to provide POLR service to its customers, the Company, like all other loadserving entities in PJM, must obtain transmission services from PJM to move electricity from
generating stations to PPLEU’s distribution system for delivery to POLR customers. PPLEU St.
4 at 31. Id.
PPLEU purchases these transmission services from PJM
under PJM’s Open Access Transmission Tariff (OATT), which is
subject to review and approval by the Federal Energy Regulatory
Commission (FERC). PJM bills PPLEU for these services at rates
set forth in the OATT. Currently, PJM is the exclusive provider of
transmission services in the PJM. Thus, all load serving entities in
the PJM region must obtain transmission services from PJM and
pay for such services pursuant to the FERC-approved OATT.
Id. at 93-94
Under the settlement of PPLEU’s electric restructuring proceeding, PPLEU is
authorized to charge POLR customers for transmission services purchased from PJM on their
behalf. PPLEU St. 4 at 31-32; Application of Pennsylvania Power & Light Company for
approval of its restructuring plan under Section 2806 of the Public Utility Code, Docket No. R00973954 (August 27, 1998), C. Provider of Last Resort, C1 & C2 at 15-20.
The Company includes a notice in all of the rate schedules in its tariff approved
by the PUC in the Company’s restructuring proceeding, contain the following language:
“The Company will provide and charge for transmission service
consistent with the PJM Open Access Transmission Tariff
approved or accepted by the Federal Energy Regulatory
Commission for customers who receive Basic Utility Supply
[POLR] Service from the Company unless such customers obtain
transmission service from another provider.”
PPLEU St. 4-R at 24.
125
Under these tariff provisions, PPLEU has charged transmission service rates to its
POLR customers since 1999. Both its distribution and transmission rates have been under the
same rate cap which limited the Company’s ability to recover its full transmission charge costs:
The Settlement of PPLEU’s restructuring proceeding
provides that the sum PPLEU’s transmission and distribution
charges is subject to a rate cap through December 31, 2004. The
Settlement further provides that because the rate cap applies to the
sum of distribution rates and transmission rates, any increase in
transmission or distribution rates would necessitate a
corresponding decrease in the other rate until the rate cap expires
on December 31, 2004. A separate rate cap applies to rates for
generation services. The generation rate cap expires on December
31, 2009.
PPLEU MB at 94, Footnote 27.
With the expiration of the transmission and distribution rate cap at the end of
2004, the Company plans to begin to recover in its rates all of its transmission charges from
PJM. This will cause an increase in charges to POLR customers of $57 million over and above
the level of transmission charges recovered through present rates. PPLEU St. 4 at 32-33.
PPLEU proposes to recover the above-described charges for transmission services
through a reconcilable automatic adjustment clause to be called the Transmission Service Charge
(TSC). The TSC contains the following principal provisions:
The TSC will provide for recovery of all transmission service
charges incurred by PPLEU to provide electric generation services
to POLR customers.
The charge for service commencing January 1, 2005, will be a
uniform amount per kWh, initially 0.564¢/kWh, applied to all kWh
provided by PPLEU to POLR customers.
The TSC will be recalculated annually, effective January 1 of each
year, to reflect current transmission charges from PJM and
projected kWh sales.
The TSC will be reconciled annually to ensure that customers will
not pay more or less than PPLEU’s actual transmission service
charges from PJM.
126
PPLEU St. 4-R at 25.
No party opposes the Company’s right to recover these transmission service
charges in retail rates. OCA initially proposed a $3.4 million adjustment to the amount to be
recovered, (OCA St. 1at 16-17), but that adjustment was subsequently withdrawn (OCA St. 1-S
at 4). No other party proposed an adjustment to the amount to be recovered. Nor does any party
oppose annual adjustments of the TSC, except OTS which opposes the concept of a reconcilable
TSC.
The two remaining disputed issues regarding the TSC are:
(1) Whether recovery of transmission charges should be subject to
reconciliation, and
(2) The manner in which transmission charges should be allocated
among PPLEU’s retail customers.
PPLEU MB at 95-96.
A.
Reconciliation
OCA provides a clear statement of this issue. The following paragraph is largely
borrowed from the OCA Brief. In this proceeding the Company has proposed to increase its
transmission revenues and to change to the way it collects transmission revenues from its retail
customers. PPL St. 4 at 33. Starting on January 1, 2005, PPLEU proposes to increase the
amount of transmission revenue it collects from its customers by approximately $57 million and
recover these revenues through a Transmission Service Charge (TSC). Id. at 31. The proposed
transmission rate increase is designed to allow PPLEU an opportunity to collect the same amount
of revenue that it estimates it will be required to pay the PJM Interconnection (PJM), the
Regional Transmission Operator (RTO) that coordinates transmission service in PPL’s service
territory, for POLR-related transmission service. PPLEU proposes to make the TSC reconcilable
on an annual basis. The OCA has not challenged PPL’s proposal to collect the full PJM
127
transmission costs in this proceeding through a reconcilable TSC: In fact, OCA supports the
Company’s proposal in the face of criticism from other parties.
PPL proposes that it pass through the transmission charges
it must pay PJM to all of PPL’s retail customers on a uniform,
cents per kWh basis. Id. at 33. Based on the Company’s
anticipated increase in PJM transmission charges of $57 million,
the Company proposes that a uniform TSC be set in this
proceeding at 0.564 ¢ per kWh.261 Id; PPL Exh. DAK2.
Importantly, PPL has used this figure to calculate the overall
impact of the current rate proceeding on each customer class
and the system as a whole. The Company’s objective of
limiting rate shock by keeping all rate classes under a 10%
increase on a total bill basis assumes that transmission charges
are passed on to customers on a uniform basis at 0.564 cents
per kWh. Id.
(Emphasis added); OCA MB at 141-142 (Footnote included below).
The Company acknowledges that this is a departure from the existing, more
integrated, multi rate structure in place today, but explains why this is appropriate in this
proceeding:
...the current allocation actually dates back to the bundled rates that
reflected a fully integrated utility that provided its own
transmission service as part of fully bundled service. Transmission
service itself has been restructured and the transmission service
that PJM provides in the restructured environment is very different
from the transmission service that PPL Electric charged for in the
former regulated environment. PPL Electric believes that a
uniform rate across all customers and all kWh is a more
appropriate structure because (1) it is generally consistent with
how PJM bills all load servers – Electric Distribution Companies
and Electric Generation Suppliers – and (2) it permits the
26
Due to timing issues, PPL proposes that the 0.564¢ per kWh figure be approved in this proceeding
for implementation on January 1, 2005. To the extent that the rate does not accurately capture transmission billings
from PJM, PPL would reconcile those differences in late 2005 and incorporate those differences in the 2006 TSC
rate.
128
calculation of a simple cent per kWh “price to compare” that can
be used by customers who may be shopping for supply to evaluate
offers from Electric Generation Suppliers.
PPL witness Krall, PPL St. 4 at 33-34.
According to the Company, “Reconciliation of the recovery of an expense is
appropriate if the expense is substantial, the expense is subject to substantial variation, and the
variation is beyond the control of the utility. PPL Electric St. 4-R at 20. PPLEU argues
persuasively that all three elements exist here. PPLLEU MB at 96
In the Company’s view, PPLEU’s transmission charges are substantial. During
2004, PPLEU projects that it will recover from POLR customers $143 million (which, under the
rate cap, is only a portion of the total transmission charges) toward recovery of its transmission
charges. PPLEU St. 4-R at 20. By comparison, “PPLEU’s projected distribution revenues for
the same period are approximately $500 million. For 2005, following expiration of the
distribution and transmission rate cap, transmission service revenues are expected to increase by
approximately $57 million to approximately $200 million. PPLEU St. 4-R at 20”. PPLEU MB
96. This amount would represent 29 % of PPLEU’s expected distribution revenues at proposed
rates of $688 million. PPLEU Ex. Future 1, Sch. D-1; PPLEU St. 4-R at 20. PPLEU MB at 96
Also according to the Company, PPLEU’s transmission charges are subject to
substantial variation:
In recent years, transmission charges have varied as follows:
129
Year
2000
2001
2002
2003
Amount
$139,950,000
$178,406,000
$170,329,000
$194,350,000
Percentage Change
27.5 percent
-4.5 percent
14.1 percent
PPLEU St. 4-R, pp. 20 – 21. Clearly, the level of transmission
service charges has varied substantially from year to year, and it is
anticipated that those charges will continue to vary. These
variations in the level of transmission charges are the result of
many factors, including changes in the costs incurred by PJM to
provide transmission services, changes in procedures under PJM’s
OATT to allocate transmission expenses among load serving
entities, changes in the level of the coincident peak created by
PPLEU’s POLR customers and changes in the season in which
PPLEU’s coincident peak occurs, i.e., whether that peak occurs in
winter or summer. PPLEU St. 4-R at 21.
PPLEU MB at 96-97
Thirdly, the Company avers that it has no control over the level of transmission
charges that it incurs. The Company accumulates usage data on its POLR customers and submits
it to PJM. Transmission expenses are allocated among load serving entities in the PJM based on
their coincident peaks and annual energy usage. The charges are imposed under PJM’s OATT,
and reflect the actual cost of providing transmission service. Any change to the OATT must be
approved by the PJM board, and also by the FERC. One of the major factors affecting usage
levels is weather. The Company has no control over any of these.
Finally, PPLEU urges that: “Reconciliation is necessary to ensure that POLR
customers do not pay substantially more than or substantially less than PPLEU’s actual charges
from PJM for transmission services.” PPLEU MB at 96-97
B.
Positions of the Parties
OTS does not agree that there is a substantial variation of transmission costs
beyond the control of the Company. OTS opines that this is the main justification for its
130
reconcilable transmission surcharge. OTS contends that transmission charges are derived from
the OATT tariff, and that PPLEU can project them like it predicts other costs. OTS opines that
transmission-related costs are an integral part of the business of supplying electricity to
customers, and are not different, from a regulatory view point, than distribution-related costs and
other operating costs of the Company.27 OTS witness Gruber testified:
It is the position of the Office of Trial Staff that the proposed TSC
should be rejected, and that all transmission-related charges be
collected through an unbundled transmission rate that is nonreconcilable. Furthermore, PPL should not be permitted to
automatically pass transmission-related costs through to POLR
customers. The proposed transmission charge should be adjusted
based on the final transmission-related costs and kWh sales figure
determined at the end of this proceeding.
OTS St 5 at 13. In its Reply Brief, OTS clarifies that Gruber is not opposed to a TSC so long as
it is not reconciled. Tr. 529-530. As OTS points out, this is a distinction without a difference,
because “a non-reconcilable surcharge is the functional equivalent of requiring the Company to
roll those costs into its base rates.” OTS RB at 35, Footnote 9; Ref., OTS MB at 15, Footnote 15
This position effectively ignores the fact that under the Customer Choice Act,
transmission service has been unbundled, Section 2806(e) of the Code, and also ignores the
reality of that unbundling, as per witness Krall, supra.
Transmission service may now even be provided by a competing generation
supplier (EGS). If it is to be offered by an EGS trying to win over a customer, it would be useful
if that customer could compare the costs for transmission service offered by the Company and
the EGS. However, as the Company notes, shopping activity is at a low level. Generation costs
are the primary interest of most shoppers, and until the generation rate cap comes to an end,
PPLEU expects shopping activity to remain low. And when the generation cap does end, the
27
OTS also produced another witness, Gary Yocca, who supported the reconcilable TSC. OTS
witness Yocca testified, inter alia, that: “I recommend that the TSC as proposed by PPL [Electric] be approved on a
kWh basis.” OTS St. 6-R at 5. Unfortunately, OTS did not chose to rely on him.
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transmission rate will be only a small element of the shoppers’ considerations. Tr. 941-942;
OCA MB at 150
The position of OTS has no merit, is not well-founded on the law, and should be
rejected.
The Mid Atlantic Power Supply Association (MAPSA) intervened in this
proceeding to encourage the Commission to adopt reasonable measures to promote competition
in PPLEU’s service territory. According to MAPSA there is minimal shopping in the
Company’s service territory, and shopping is constrained by the generation rate cap and
collection of stranded costs. MAPSA MB at 1. MAPSA supports the Company’s TSC proposal
because it believes that the proposal will promote competition. MAPSA agrees that the uniform
TSC provides a simple price to compare that shopping customers may use to evaluate offers
from competitive suppliers.
MAPSA believes that a uniform TSC among rate classes and customers is simple
and easily understood by customers. It maintains a plain vanilla transmission product for
PPLEU and leaves other more sophisticated products to be offered by competitive suppliers,
which MAPSA believes is consistent with the standards and policy of the Customer Choice Act.
MAPSA also supports the proposed annual reconciliation of the TSC to reflect the actual
transmission costs incurred by the Company, because it is designed to recover no more and no
less than the actual transmission costs. MAPSA MB at 1-3
OCA avers that “CCC (PEC/WalMart) witness Selecky proposes that the TSC not
be approved in this proceeding. CCC St. 1 at 13. If the Commission does approve a TSC
charge, CCC proposes that the charge should reflect how PPL incurs those charges. Id. Selecky
proposes that each class be billed based on each classes’ transmission level demand allocators.
Id.”
OCA also avers that “US DOD witness Kincel proposes that the allocation of
PPL’s transmission revenue requirement be done on a pure demand basis.” US DOD St. 2 at 25.
132
Under the US DOD approach, PPLEU could use the same five coincident peak methodology it
currently uses to allocate the peak demand among rate schedules. Id.
The OCA submits that the proposals of both the CCC and US DOD do not
capture the costs that PPLEU incurs to serve its retail customers, because both of these proposals
pass on all of PJM’s transmission charges to customers on a purely demand basis, despite the
fact that roughly 30% of transmission charges are billed on a usage basis. Neither of these
proposals accurately captures how the Company is billed by PJM or the fact that kWh usage
plays a part in determining the customer’s burden on the system. These proposals would also
produce even greater volatility in transmission rates by linking 100% of transmission revenue
requirements with each class’s seasonal maximum demand. For these reasons and those outlined
subsequently, OCA argues that the CCC and US DOD proposals should not be adopted. OCA
MB at 146, Footnote 44
OCA supports the purpose and design of the Company’s TSC proposal. The
OCA opines “that PPL accurately captures the nature of transmission service as it is provided in
today’s unbundled environment.” OCA endorses PPL’s proposed uniform rate proposal as a
reasonable way to collect transmission revenues during this continuing period of transition. OCA
asserts that: “A uniform rate also allows the Company to meet its overall allocation goal by
keeping rate increases for all rate schedules under 10% on a total bill basis”:
As detailed above, the OCA strongly supports this objective to
keep all rate schedules’ revenue increases under 10% – an
approach which effectively eliminates rate shock, incorporates the
principle of gradualism, and recognizes the transitional period in
which PPL continues to operate.
OCA MB at 142-143
PPLICA also states that electric service was unbundled into three parts by the
Customer Choice Act: “The Competition Act restructured the manner in which electric service
is provided in Pennsylvania by “unbundling” electric service into three separate parts –
generation (the provision of electricity supply), distribution (the local delivery of electricity to
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retail customers), and transmission (the movement of electricity at higher voltages from the
generating source to other areas of the utility’s service area)” PPLICA MB at 61. PPLICA then
takes the next step and argues that transmission rates should be viewed as stand-alone rates, and
should be set in isolation from distribution rates. PPLICA supports the TSC but only so long as
it is not charged on a cents per kWh basis.
C.
Reconciliation Methodologies
Allocation of costs for transmission service is the real deep-rooted dispute here.
The Company, OCA and MAPSA support using a per kWh charge. PPLICA and OSBA
ardently advocate for a charge based on cost causation. They argue for a rate basically mirroring
the way PJM breaks down its charges to PPLEU and other load-bearing entities (EDCs and
EGSs) under the OATT, which is about 70% based on consumption, and 30% based on demand.
The Company has set forth 3 possible methods, although it by far prefers its first proposal;
PPLICA has set forth another proposed rate; and OSBA has proposed a kinder, gentler
modification of PPLICA’s proposal. A summary of PPLEU’s three proposals follows below:
PPLEU’s principal proposal in this proceeding is to allocate
and recover transmission service costs on the basis of a uniform
amount per kWh from all POLR customers. Initially, the TSC
would be $0.0564/kWh. PPLEU, St. 4-R, pp. 25-26. This
proposal [would be] be simple for customers to understand, simple
for PPLEU to administer, and simple for the Commission to audit.
In addition, it will virtually eliminate the possibility of substantial
variation in TSCs from year to year as a result of seasonal shifts in
PPLEU’s annual peak load. Further, the uniform cents per kWh is
essential to PPLEU’s overall rate allocation objective of having no
single rate class, as a whole, experience increases in total bills in
excess of ten percent. PPLEU St. 4 at 27; PPLEU St. 4-R at 28.
Under PPLEU’s first alternative proposal, TSCs would be
allocated to each rate class based upon principles of cost causation
but recovered based upon a uniform rate per kWh within each rate
class.
Under its second alternative, PPLEU proposes that that
134
Reconciliation of the TSC should be accomplished over the
following three broad classes of customers: (1) all residential
customers, (2) commercial, municipal and small industrial
customers and (3) large industrial customers.28 Reconciliation by
large customer classes, rather than by individual rate schedules,
will reduce volatility in rates due to reduced or variable kWh sales
for rate schedules with limited usage. Using broad customer
classes for purposes of reconciliation also will reduce substantially
the costs of administering recovery of transmission service
charges.
PPLEU St. 4-R at 32-33; PPLEU MB at 99 (Footnote included above)). According to witness
Krall the groups in this last alternative are the same ones used in reconciliation of the Company’s
CTCs and ITCs. Reconciliation by large groups instead of by numerous rate schedules will
reduce volatility in rates for smaller, individual rate schedules. PPLEU St 4-R at 32. These
schedules also have at the bottom rates calculated for these three groups.
The Company submits that its “alternative 2” method has the same effect as
OSBA’s proposal discussed below. The company expands the data by including more
customers. OSBA expands the data by including more time.
There are two main problems to solve by allocation methods:1) high volume
customers believe that they pay a disproportionate share of any uniform charge based on kWh,
and, 2) these customers want the rates based on cost causation. But in this case, rates based
solely on cost causation are volatile in the extreme because the Company is a twin peaking
company, i.e., its peak can come in either the summer or the winter.
The Company has, through witness Krall, provided a comparison of rates based
on demand based on a winter peak, Exh DAK 3, and a summer peak, Exh DAK 4. These
exhibits show the rates per kWh calculated on demand, and the deviation of this rate from the
These customer classes are identified specifically at PPLEU St. 4-R at 31 – 32. They are the same
as the three customer classes used for reconciliation of PPLEU’s Intangible Transition Charges and Competitive
Transition Charges.
28
135
average. Many variations can be found per class on these two exhibits. PPLEU has focused on
one example to make its point:
For example, in a year in which PPLEU was winter
peaking, Residential Thermal Storage (RTS) customers would
have the highest TSC of 1.097¢ per kWh, which is almost twice
the average kWh rate. In contrast, in years in which PPLEU is
summer peaking, RTS customers would have the fifth lowest TSC,
of $0.421¢ per kWh, which is substantially less than the average
TSC. Thus, using RTS customers as an example, a TSC based on
a winter peak can be 260 percent of a TSC based on a summer
peak for the same customer (1.097¢/kWh ÷ 0.421¢/kWh). Thus,
following strict principles of cost causation would create TSCs that
are volatile from year to year, especially for certain rate classes.
PPLEU MB at 105.
OCA prepared the following chart based on PPLEU witness Krall’s Exhibits
DAK3 and DAK4 to show what each rate schedule’s TSC rate would look like in a winter
peaking year and a summer peaking year using the same total revenue requirement:
TSC RATES UNDER ALTERNATIVE RATE PROPOSALS
(CENTS PER KWH)
RS
RTS GS-1 GS-3 LP-4 ISP LP-5 IST LP-6 LPE GH SL/A
P
L
Winter Peak
.712
1.09
7
.541
.470 .459 .456 .455 .389 .393 .490 .765 .604
Summer Peak
.597
.421
.727
.640 .538 .541 .533 .441 .553 .205 .590 .161
Source: PPL Exh. DAK3; PPL Exh. DAK4;
OCA MB at 147.
OCA points out that “As seen in this chart, under the alternative proposals, rate
classes would experience significant fluctuations in rates from year to year.” For example, this
136
chart shows graphically the fluctuations in Rate RTS described by PPLEU. According to OCA
“A similar, though less dramatic, effect is seen for rate RS.”
OCA concludes that:
Under PPLICA witness Baron’s methodology, if PPL winter
peaks, residential customers would see an increase of about $20
million in transmission charges. Tr. at 895. Even in years that
PPL summer peaked, Rate RS would pay more than under the
Company’s original proposal. PPL Exh. DAK4. As PPL witness
Krall testified, the Company has peaked twice in the summer and
twice in the winter over the last four complete calendar years and
there is no clear trend as to when PPL will peak in the future. PPL
St. 4-R at 29; Tr. at 894.
OCA MB at 148
D.
Comparative Allocation Summary
The parties in this proceeding have presented a range of proposals for allocation
of transmission service costs. These proposals differ primarily in the importance attributed to
rate stability and cost causation. Rates based exclusively upon principles of cost causation, as
explained above, are subject to substantial variation from year to year based principally on
whether PPLEU was a summer peaking or winter peaking electric distribution company during
the prior year. Thus, the more that the allocation of transmission costs follows cost causation,
the more volatile TSCs become. Conversely, but for the same reasons, the more stable that TSCs
are from year to year, the less they follow cost causation.
The five proposals, ranked based on stability of rates, are as follows:
PPLEU’s initial proposal for TSCs to be a uniform rate per/kWh
for all rate classes.
137
OSBA’s proposal to allocate each year’s TSCs among rate classes
based upon a five year average of each rate class coincident peak
and kWh usage.
PPLEU’s second alternative proposal under which TSCs would be
allocated among three broad categories of customers with a
different uniform rate per/kWh for each broad category.
PPLEU’s first alternative proposal under which TSCs would be
allocated to each rate class based upon principles of cost causation
but recovered based upon a uniform rate per kWh within each rate
class.
PPLICA’s proposal under which TSCs would be allocated to each
rate class based upon the PJM OATT methods and recovered from
rate classes with interval metering based upon demand and energy
cost elements.
In contrast, the five proposals ranked on the basis of cost causation, are as follows:
PPLICA’s proposal under which TSCs would be allocated to each
rate class based upon the PJM OATT methods and recovered from
rate classes with interval metering based upon demand and energy
cost elements.
PPLEU’s first alternative under which TSCs would be allocated to
each rate class based upon principals of cost causation but
recovered based upon a uniform rate per kWh within each rate
class.
PPLEU’s second alternative proposal under which TSCs would be
allocated among three broad categories of customers with a
different uniform rate per kWh for each broad category.
OSBA’s proposal to allocate each year’s TSCs among rate classes
based upon a five year average of each rate class’s coincident peak
and kWh usage.
PPLEU’s initial proposal for TSCs to be a uniform rate per kWh
for all rate classes.
PPLEU MB at 108-109.
138
In its Reply Brief, OSBA takes strong exception to the Company’s ranking of
plans on cost causation as “baseless”:
....PPL arbitrarily claimed that its alternative proposals are
somehow more consistent with cost causation than the OSBA
proposal. However, PPL provided no evidence or explanation as
to why its proposals (which involve averaging rates across classes)
are any more consistent with cost causation than OSBA’s proposal
(which involves averaging cost causation factors over five years).
Consequently, the OSBA proposal to utilize the underlying
PJM transmission rate design, but to smooth out the volatility by
applying a rolling five year average on the peak demand
component is the best solution to a difficult problem.29 (Footnote
included below)
OSBA RB at 19
PPLICA’s and OSBA’s proposed adjustments are admirably set forth and
supported by the testimony and exhibits of their respective witness: Stephen J. Baron, PPLICA
St 1 and Exhibits; Messrs. Knecht and Ewen, OSBA St 1 and Exhibits. PPLICA responds to the
need for gradualism by proposing to phase in its adjustment over three years.
PPLICA also contends that the Company’s preferred proposal, the uniform cents
per kWh, will create a distortion in the comparison-to-shop transmission price for customers.
This would be created by an EGS using something close to the PPLICA method to set its
transmission rates, and thus showing a different rate for the same priced service. PPLEU
disagrees that this would be a significant factor, points out that PPLICA has not shown how
EGSs set their transmission rates, and also points out that MAPSA, which represents competitors
supports the PPLEU preferred proposal. PPPLEU MB at 102-104
On balance, the ALJ recommends that the Commission allow the Company to put
the reconcilable TSC as proposed in place. The parties did not litigate interest on over and under
29
Other parties have commented favorably on the OSBA proposal. See OCA Main Brief at 152153; PLUG Main Brief at 18-19; DOD Main Brief at 27. Even PPL conceded that it is a methodology that provides
a high degree of rate stability. See PPL Main Brief, at 108.
139
collections, but the ALJ has provided for it in the Order. She finds that PPLEU’s version of
gradualism is actually gradual for the bulk of its ratepayers, and that the uniformity will in fact
be easier for customers to understand and the Company to administer. If the Commission does
not agree with this, the ALJ recommends the Company’s alternative 2 which would be similar to
the ITC and CTC reconciliations.
2.
RATE STRUCTURE – DISTRIBUTION
A.
Introduction
This is the first base rate case in which the Commission has considered an
increase in rates for distribution service alone, and thus the first proceeding where the
Commission will set rate structure for unbundled distribution service. The same standards for
setting rate structure still apply:
A properly designed rate structure will not unduly burden one class of
ratepayers to the benefit of another. The Public Utility Code maintains that rates
“shall be just and reasonable and in conformity with regulations or orders of the
commission.” 66 Pa. C.S.A. §1301. The Code further dictates that “[n]o public
utility shall…make or grant any unreasonable preference to any person,
corporation….No public utility shall establish or maintain any unreasonable
difference as to rates, either as between localities or as between classes of
service.” 66 Pa. C.S.A. §1304. Proper interpretation of this statute does not
require each class to be charged the same rate. The Court has upheld differences
in rates charged to different classes to the extent there was a reasonable basis for
the discrepancy. Peoples Natural Gas Company v. Pa. P.U.C., 47 Pa. Cmwlth
512, 409 A2d 446 (1979).
Succinctly stated in Pa. P.U.C. v. West Penn Power: [p]ublic utility rates
should enable the utility to recover its cost of providing service and should
allocate this cost among the utility’s customers in a just, reasonable and
nondiscriminatory manner.
73 Pa. P.U.C. 454, 510, 199 PUR 4th 110 (1990).
OTS MB at 68
Usually, the steps are to first perform a cost of service study (COSS), and then to
allocate the increase across the rate classes according to their costs, minimizing subsidies,
avoiding sharp increases, and satisfying the utility’s need to recoup the total increase allowed. In
140
this case, PPLEU performed a fully distributed cost of service study for both the historic and the
future test years. OCA also performed a COSS based on a different concept. OSBA differed
with the Company’s (COSS) and that of OCA. OSBA replicated the PPLEU COSS when the
Company declined to provide a fully functional, electronic version of its COSS because of
confidentiality concerns. OTS and PPLICA did not introduce their own COSSs.
The Company has performed these steps, and allocated the increase in such a way
as to meet its goal to keep the increase to all customer classes below 10%. OCA accepts this
goal, and agrees with the Company’s allocations. PPLICA and OSBA do not accept this goal
because in meeting it, the Company has not in their view sufficiently reduced the subsidies
received by some classes, and paid in their view, by their clients. OCA has written an excellent
summary of the Company’s allocation:
As part of its distribution rate increase request of 31% (or 8.14% on a total
bill basis), PPL has presented a proposed revenue allocation to the various
customer classes based, in part, on its cost of service study, and in part on
principles of fairness and gradualism as the Company completes its transition to
unbundled rates. PPL St. 4 at 26-27. With the exception of rate classes ISA and
PRS, the Company has proposed increases for all of its class revenue
requirements that range in percentage increases from 4.3% to 9.9% on a total bill
basis.31 PPL St. St. 6 at 10; PPL Exh. Fut. 1, D3 at 7A. Overall rates for ISA and
PRS customers would remain unchanged under the Company’s allocation. Under
the Company’s allocation, Rates IS-T and LP-6 receive distribution revenue
reductions. PPL Exh. Fut. 1, D3 at 6. For the Residential class under Rate
Schedule RS, the Company has proposed an overall increase of 9.7% on a total
bill basis as compared to the system total of 8.1%. For the Residential Thermal
Storage Class (“RTS”), the Company has proposed an increase of 9.9% on a total
bill basis. Id. at 7A.
The Company also proposes to modify the Rate RS residential rate
design by eliminating one of the usage blocks, increasing the customer charge and
including 200 kWh of usage in the customer charge. Under the Company’s
proposal, the Rate RS customer charge would increase from $6.55 to $12.20, and
include the first 200 kWh of usage. Exh. OGK2 at 5. The rate for the next 600
kWh of usage would increase from 1.612¢/kWh to 2.198¢/kWh. Id. For all
remaining kWh of usage, the Company proposes an increase from 1.489¢/kWh to
1.879¢/kWh. Id. For Rate RTS, the Company proposes to increase the customer
charge from $15.21 to $20.20. Id. at 6. The Company further proposes that for
each on-peak kW in excess of 2 kW of demand, Rate RTS customers would see a
decrease from 90¢/kW to 56.3¢/kW. Id.
31
Total bill basis includes the distribution, transmission and generation components of the bill.
141
OCA MB at 99-100.
OCA has also prepared a chart showing the proposed revenue allocations put
forward by the various parties, noting that it has proposed overall reductions to the Company’s
revenue requests, and that this chart is for comparison purposes only. It is included further on in
the discussion.
The OCA agrees with the Company’s goal in this case to move each class closer
to system average rate of return, and believes that it has allocated the rate increase so as to
implement the concept of gradualism in a fair way. CCC also endorsed the Company’s proposed
revenue allocation. OCA also opines that the Company’s proposed allocations meets the goal of
moving each class closer to system rate of return under both its own and OCA’s cost of service
study. OCA argues that:
the other parties’ proposals should be rejected because they violate principles of
gradualism and are based entirely on the Company’s study which significantly
understates the residential class RS rate of return. When the OCA study is used as
a guide, the allocations proposed by the other parties are not supportable.
OCA MB at 121.
B.
Cost of Service Studies
The Company performed fully distributed cost of service studies for both present
rates and future rates for the future and historic test years. PPLEU witness Joseph M. Kleha
sponsored these studies. PPLEU St 5, 5-R; Exh JMK 1, JMK2. These studies are performed
using a “minimum size” method.
In preparing its cost allocation study, PPL Electric categorized its
distribution plant into several functional categories (e.g., substations, line
transformers, overhead lines) and then “subfunctionalized” these categories based
upon primary voltage (3 phase 12 kV or 3 phrase 23 kV) or secondary voltage
(everything below 3 phase 12 KV). Ex. JMK3, p. 1. Primary distribution system
costs are classified as demand related. Secondary distribution system plant was
separated into demand and customer components using a “minimum size system
142
study,” which determined the current cost of the “minimum size” distribution
system necessary to provide reliable distribution service to customers. PPL
Electric St. 5-R, p. 6; Ex. JMK3, p. 10. The cost of the minimum system is
classified as customer-related, the remainder of secondary distribution costs is
classified as demand related.
Customer related costs were allocated to customer classes based on the
number of customers in each rate class. Demand costs were allocated based on
each rate class maximum non-coincident peak (“NCP”) demand. PPL Electric St.
5-R, p. 4. Under the maximum NCP demand method, PPL Electric’s primary and
second demand-related distribution costs are allocated based upon the relationship
of a class’s maximum annual NCP demand to the sum of the maximum annual
NCP demands of all classes sharing in such costs. See Ex. JMK1, p. 6; Ex.
JMK2, p. 6.
PPLEU MB at 162-163
OCA witness Galligan performed a “peak and average” study, based on a 50%
weighting of average demands and a 50% weighting of peak demands. OCA contends that the
minimum system study is flawed because the plant has substantial load carrying capability, and
the components are too large, and offers its study as a basis for correction of PPLEU’s cost of
service study. OCA sets forth the problems with the Company’s study, the features of its own
study, its superiority, and the flaws in the criticisms of its study and the proposals of other parties
at length in its Main Brief at 102-119. This summary cannot do justice to that careful analysis
and discussion. However, in sum, OCA contends that its study show a much lower and more
accurate class rate of return for the residential clients.
OCA argues that its
...witness Galligan’s modified study properly allocates costs in a more accurate
manner than does the Company’s study. The peak and average study captures the
practical and realistic view of why PPL’s distribution system was built, and why
those costs were incurred. The peak and average methodology has been used in
the gas distribution industry, is an accepted ratemaking methodology, and is an
appropriate way to allocate costs for an electric distribution company in
Pennsylvania’s restructured environment. The OCA submits that Mr. Galligan’s
study is a useful guide for setting rates in this proceeding and should be adopted
by the Commission.
OCA MB at 119
143
The Company rejects OCA’s “peak and average” method as being inconsistent
with proper cost allocation procedures. Citing the NARUC Utility Cost Allocation Manual,
PPLEU says that there is no energy component of distribution related facilities, only demand and
customer components. It then avers that OCA’s proposal effectively ignores customer
components. OSBA also argues against OCA’s approach, contending that it is not consistent
with cost causation, fairness, or the NARUC-approved approach. PPLEU MB at 164
The Company also rejects OSBA’s preferred “zero-intercept” model. PPLEU’s
actual experience in attempting to use the zero-intercept model found it impractical in light of
available accounting data. Negative costs were obtained for wood poles and other Equipment
PPLEU St 5-R at 7. The Company and OCA agree that “OSBA’s “very rough calculations”
cannot begin to serve as a basis for cost allocation.” PPLEU MB at 164. The ALJ also agrees.
PPLEU argues that “consistency in cost allocation is indisputably important for
PPL Electric and its customers, and PPL Electric has used the same methods of cost allocation
here which have been approved by the Commission in prior PPL Electric rate proceedings.” The
ALJ opines that entry into a transitional period of regulation and deregulation might call for a
different approach to COSS for unbundled rates. However, there is no evidence on this record
that would compel a different approach in this case. The Company argues that because the
resulting allocation of revenue and rate design is reasonable, and no party has offered any
compelling reason why a change in PPL Electric’s cost allocation methodology is now
appropriate, PPL Electric’s cost allocation study should be approved. PPLEU MB at 161-162
The ALJ remains mindful that cost of service studies are not regarded as fully
accurate studies, and that their primary function is to allow the Commission to use them as a
guide. The ALJ does not recommend that the Commission adopt either PPLEU’s or OCA’s
COSS, and rejects US DOD’s request that the Commission should define the kind of COSS it
wants to receive in the future. However, in this case, the ALJ recommends that the Commission
rely primarily on the Company’s study for guidance.
144
C.
The Company’s Proposed Revenue Increase Allocation
The Company has proposed changes in rates for each rate schedule designed to
move each rate schedule closer to the system average rate of return that was proposed by the
Company, while limiting the overall increase to 10%. PPL St. 4 at 27. With the exception of
rate schedules ISA and PRS, these increases range from 4.26% to 9.9% on a total revenue basis.
PPL Exh. Future 1, Sch. D3 at 7A. Rate schedule ISA and PRS are allocated 0% increases on a
total bill basis. Id. The Company also allocates a reduction in distribution revenues for rate
schedules IS-T and LP-6. PPL Exh. Fut. 1, D3 at 6.
The OCA supports the Company’s proposed revenue allocation. The following
chart provides a summary of the different revenue allocations proposed by the parties in this
proceeding based on the full revenue increase requested by the Company. As discussed above,
the OCA has proposed overall reductions to the Company’s revenue request, and provides this
chart for comparison purposes only.
145
PROPOSED REVENUE ALLOCATIONS
PPL39
OCA
OTS
OSBA
PPLICA
D.O.D.
80,930,691
80,930,691
97,378,000 117,101,000 133,086,281 120,077,000
568,224
568,224
2,984,000
1,996,000
6,666,247
8,217,000
32,127
32,127
54,444
21,958,604
21,958,604
16,448,000
9,127,000
6,697,273
12,644,000
43,087,505
43,087,505
34,483,000
24,846,000
6,726,858
12,172,000
10,750,484
10,750,484
8,474,000
5,307,000
1,917,858
2,845,000
383,427
383,427
240,000
90,000
(27,368)
(86,000)
18,733
18,733
(101,000)
19,000
(187,042)
(380,000)
(564,896)
(564,896)
(625,000)
(565,000)
(564,896)
(953,000)
(97,808)
(97,808)
(110,000)
(98,000)
(97,808)
(175,000)
90,802
90,802
64,000
90,000
29,688
30,000
84
84
(44,000)
(1,000)
(241,668)
(483,000)
12,701
12,701
4,420
56,990
56,990
24,263
RS
RTS
RTD
GS-1
GS-3
LP-4
IS-P
LP-5
IS-T
LP-6
LPEP
ISA
IS-1
BL
SA
SM
SHS
SE
TS
SI-1
372,717
83,755
1,594,681
43,568
3,257
1,870
372,717
83,755
1,594,681
43,568
3,257
1,870
763,000
2,829,000
1,362,213
312,997
5,631,815
316,770
9,637
6,886
7,192,000
GH-1
GH-2
(LP5S)
PRS
Total
2,436,077
534,741
46,696
2,436,077
534,741
46,696
2,350
1,557,000
1,219,000
41,000
47,000
493,192
112,529
10,439
0
162,345,030
0
162,345,030
162,345,000
162,345,030
0
162,345,030
5,000
162,323,000
Sources: PPL Exh. Fut. 1, D3 at 7; PPLICA Exh. SJB-11; PPLICA Exh. SJB-2R; DOD Exh.
KLK-11; OSBA Exh. IEc-2.
The OCA generally agrees with the Company’s proposal in this case to move
each class closer to system average rate of return. OCA St. 4 at 21. The Company’s proposed
allocation of the rate increase accomplishes this goal under both the Company’s and the OCA’s
39
CCC endorsed the Company’s proposed revenue allocation. CCC St. 1 at 9.
146
cost of service studies. “However, the other parties’ proposals should be rejected because they
violate principles of gradualism and are based entirely on the Company’s study which
significantly understates the residential class RS rate of return. When the OCA study is used as a
guide, the allocations proposed by the other parties are not supportable.” OCA MB at 121
While the OCA disagrees with the Company’s assignment of costs in its cost of
service study, the OCA agrees that principles of gradualism, avoidance of rate shock, and
fundamental fairness requires a measured approach to bringing rates in line with costs. The
Company recognized that rates should be increased gradually during this transitional period.
PPLEU witness Krall and OCA witness Galligan agreed that electric rates remain in a
transitional period until the generation rate cap expires. They also agree that it is inappropriate
to move rapidly to “correct” the allocation of distribution revenue requirements when other bill
components may continue to be incorrect. PPL St. 4-R at 34; OCA St. 4 at 21. OCA continues:
In past cases, cost of service studies reflected all elements of
electric service, from production, to transmission, to distribution. The
incumbent utility provided all aspects of service, and as a result, cost
studies were designed to determine each class’ rate of return, factoring in
all elements of service, relative to the Company’s overall rate of return. In
prior cost of service studies, it was not separately distinguished as to
whether a residential class was paying a higher rate of return on one
component of bundled service, such as generation, and a lower rate of
return on another component of service, such as distribution. It was the
overall class rate of return that was looked at in the cost of service study to
serve as a guide when setting rates.
OCA MB at 122-123.
In its filing, the Company recognized this key point. It is not possible to achieve
rates that completely reflect principles of cost causation in this case because distribution rates in
past cases were not separated out to reflect those same principles. PPLEU St 4 at 26-27. These
effects are visible in the Company’s last base rate case. OCA St 4 at 22
PPL witness Kleha stressed that the Company’s current rates reflect prior cost
considerations as follows:
147
PPL Electric’s current rate structure is a product of the rate unbundling
process which occurred in its electric restructuring proceeding. The
unbundling of rates in that proceeding was based on the cost allocation
study from PPL Electric’s 1995 base rate proceeding which reflects the
Company’s operation as a vertically integrated electric company. Thus,
PPL Electric’s current rate structure contains vestiges of its prior vertical
integration. The rate cap on PPL Electric’s transmission and distribution
rates ends on December 31, 2004, but the cap on generation rates extends
through 2009. It would be inappropriate, in my view, to undertake a major
revision to PPL Electric’s cost allocation procedures in these
circumstances. Any such review should await the expiration of the cap on
generation rates.
PPL St. 5-R at 3-4.
The Company’s allocations recognize the transition:
The OCA submits that the allocation of the rate increase proposed
by PPL and accepted by the OCA recognizes the transition that PPL
continues to undertake while making progress in moving classes closer to
the overall system rate of return. This revenue allocation produces a fair
and reasonable sharing of the burden of this rate increase.
D.
Scale Back is Fairer than Reallocation
If the Commission grants PPL a revenue increase less than the full request, the
Company and OCA agree that a proportional scale back is a fair way to reduce the increase.
CCC recommends that if the Commission reduces PPL’s requested revenue request, any
reduction should benefit only those customer classes that are recovering more than their costs
under the Company’s cost of service study. CCC St. Selecky at 9. However, OCA asserts that
the Company’s study cannot be used as the sole guide in this proceeding for setting rates because
it does not accurately capture how PPL incurs costs. Nor, according to OCA, can other parties
allocation proposals be used because they are based on the flaws in the Company’s proposals;
Under the OTS allocation, Rate RS would receive $60 million of
$101 million revenue increase that it believes is appropriate in this
proceeding, or 60% of its proposed increase. OTS St. 4 at 11 (Errata
148
Sheet items 13 & 14). For any revenue increase in excess of $101 million,
OTS proposes an across the board allocation. Id. at 17. In effect, the OTS
proposal would allocate 60% of any increase to Rate RS. At the OCA’s
proposed increase of $115 million, OTS would allocate approximately $69
million to Rate RS, while the Company’s proposal, adopted by the OCA,
would result in an increase of approximately $57 million.
Neither the CCC nor the OTS scale back proposals adhere to the principles that
guided the Company’s allocation that is supported by the OCA. The OCA submits that the
Company’s proposed allocation at its full request is fair, and there is no reason to change the
proportionate increases to rates in a way that distorts that fair allocation should a scale back be
necessary.
The OCA submits that the revenue allocation proposed by the
Company is reasonable, especially when considering these revenue
allocations in light of OCA witness Galligan’s revised study. The OCA’s
adoption of PPL’s revenue allocation is based on fundamental principles
of gradualism and fairness as well. The Commission must not move too
quickly to adjust rate components resulting from unbundling without
considering the effect of the unbundling process on all rate elements.
Even if the Commission does not accept the OCA’s modified cost of
service study, it should accept the Company’s proposed revenue allocation
for the reasons advocated by the Company and the OCA – including the
fundamental fairness concerns that have arisen due to the unbundling of
the industry. The OCA’s modified cost study simply demonstrates that the
Company’s revenue allocations are even more reasonable.
OCA MB at 126.
E.
The Alternative Revenue Allocations Should Be Rejected
According to OCA, the Company has proposed a revenue allocation of its full
request that fairly distributes any increase in rates while bringing the different classes closer to
the system average rate of return. Some of the parties, however, have offered different
allocations that shift more of the burden of any increase onto residential customers. Each of
these alternate rate increase allocations should be rejected. OCA’s summaries are included
below:
149
OSBA’s Proposal
Under the OSBA’s proposed revenue allocation, rate schedule RS would pay
$117.1 million of the Company’s proposed $162.3 million distribution rate increase,
compared to the $80.9 million proposed by PPL and the OCA. OSBA Exh. IEc-2. For
rate schedule RTS, the OSBA proposes an increase of $1.996 million, compared to the
Company’s and the OCA’s proposed increase of $568,000. Id. On an overall bill basis,
the OSBA’s proposed allocation results in a Rate RS increase of 13% and a Rate RTS
increase of 16%. OSBA Exh. IEc-2. In contrast, under the Company’s allocation, Rate
RS would receive a 9.7% overall increase, and Rate RTS would receive a 9.9% overall
increase. PPL Exh. Fut. 1, at 6A. On a distribution only basis, the OSBA’s allocation
results in a 39.8% increase for Rate RS, and a 56.8% increase for Rate RTS. Id. Under
the Company’s allocation, Residential customers would receive a distribution increase of
27.5% for Rate RS and 16.2% for Rate RTS. PPLICA Exh. SJB-8.
The OTS Allocation Proposal
The OTS allocation proposal is based on the Company’s cost study. The OTS’
revenue allocation is based on a total revenue increase of $101 million. OTS St. 4 at 5
(per Errata Sheet item 1). PPLICA witness Baron made an adjustment to the OTS
distribution allocation proposal in order to compare it with the other allocation proposals
in this proceeding that used the Company’s full revenue request for comparative
purposes. See PPLICA Exh. SJB-2R. When the OTS revenue allocation is based on the
Company’s full revenue request, Rate RS would be allocated a $97.3 million increase and
Rate RTS would receive a $2.98 million increase as compared to the OCA’s and the
Company’s allocations of $80.9 million and $568,000, respectively. Id. These rate
increases were designed to bring residential class rates of return closer in line with the
Company’s overall return as defined by the Company’s cost of service study. OTS St. 4
at 10. The OCA submits that the Company’s study cannot be relied upon as the sole
basis to set rates, and that the OTS rate allocation based on that study increases
residential class rates beyond what the Company has proposed to an unreasonable level.
The OTS allocation proposal also fails to take into account PPL’s transition.
The DOD Allocation Proposal
The DOD proposed distribution allocation increases the amount collected from
residential customers, placing a particularly large increase on Rate RTS. For Rate RS,
DOD proposes an increase of $120 million, compared to the Company’s requested $80.9
million increase. DOD Exh. KLK-11. For Rate RTS, DOD proposes an $8.2 million
increase, compared to the Company’s requested $568,000 increase. Id. Under the DOD
allocation, Rate RS would see a 41% distribution increase, and Rate RTS would
experience a 234% increase. Id. The DOD allocations attempt to bring each rate
schedule closer to the system average return based on the Company’s study. DOD
proposes to bring all schedules that are over-paying according to the Company’s study to
150
150% of the system rate of return. DOD St. Kincel at 24. Once these classes are set at
150% of the system rate of return, all remaining classes would be set at an equal rate of
return. Id. At PPL’s full revenue request, the remaining classes (including rates RS and
RTS) would be set at 80% of the system average rate of return. DOD Exh. KLK-11.
The PPLICA Allocation Proposal
PPLICA also offers an alternative to the Company’s allocation. Under PPLICA’s
proposal, each rate schedule would be allocated rate increases in an effort to rapidly
move each rate schedules indexed rate of return, in strict adherence to Company’s cost of
service study, in line with the overall system return. PPLICA proposes that each rate
class that is paying more than the system average return move 50% closer to the system
average at this time, followed by 25% reductions in the following two years.40 PPLICA
St. 1 at 40. At PPL’s full request, the initial 50% reductions would result in Rate RS
receiving a $133 million distribution increase, and Rate RTS receiving a $6.6 million
distribution increase. Exh. SJB-11. On a distribution only basis, PPLICA’s proposal
results in increases of 45% for Rate RS and 190% for Rate RTS. Exh. SJB-10. On a
total bill basis, PPLICA proposes that Rate RS receive a 16.3% increase, and Rate RTS a
38% increase. Id. These increases do not include the additional increases PPLICA
proposes to have phased in over the subsequent two years.
OCA MB at 128-132.
The ALJ would like to see some relief given to small business consumers of
PPLEU’s distribution service. However, she does not see how OSBA’s proposal can be
implemented without skewing the results for all other classes. The Company’s revenue
allocation, while based on a disputed COSS, produces fair results. As Company witness Kleha
pointed out in his Rebuttal testimony, “The central issue to be considered is whether PPL
Electric’s proposed allocation of the revenue increase and its rate design are reasonable.” PPL
St. 5-R at 4. The Company and OCA argue that the Company’s proposed revenue allocation
produces a reasonable result. OCA supports its adoption in this proceeding. The ALJ agrees.
40
PPLICA does not make any adjustments to rate schedules IS-T and LP-6, two classes that take
service at transmission voltage and already receive distribution rate reductions under PPL’s proposed allocation.
PPLICA St. 1 at 40.
151
3.
RATE DESIGN - INCREASED CUSTOMER CHARGES
A.
Rate RS Rate Design
Both OTS and OCA oppose the increase in the customer charge to the residential
class rate RS. As proposed by the Company, the customer charge for rate schedule RS will
increase by 86%, and will also include 200 kWh of usage.
According to OTS, a customer charge should only recover “fixed” costs that are
related to customer service, i.e., billing, meter reading, service connections, accounting and
collections, etc., but not usage charges. The rate RS customer charge should be set at $8.25.
OTS St 4 at 7; OTS MB at 71. According to OCA “the proposed customer charge includes
significant costs that have not been considered “customer” costs in the past, and should not be
considered “customer costs in the future.” OCA also objects to the inclusion of usage in the
customer charge. OCA MB at 135.
However, OTS is in agreement with the monthly charge to be assigned to
residential Rate RTS, without the reduction in the distribution charge for on-peak kW in excess
of 2 kW. According to witness Yarolin this class shows a negative rate of return, and no
reduction in rates is warranted. OTS actually recommends an increase in rates for this class in
order to bring its class rate of return up to at least 0. OTS St 4 at 14; OTS MB at 72
In comparison, at the Company’s full revenue request, the OCA recommends that
the Rate RS customer charge be set at $8.00 per month, and that the usage charges for the each
of the three existing blocks be increased in a uniform manner. OCA St. 4 at 25. For Rate RTS,
the OCA recommends that the customer charge be set at $16.66, and that the rate for on-peak
kW demand in excess of 2 kW be set at $1.25 per kW. Id. at 26.
152
The Commission has held that the customer charge should be designed to recover
those costs that are directly associated with the metering and billing of residential customers. In
a 1985 West Penn Power case, the Commission adopted the staff definition of customer charge
costs as being “basic customer costs”: “those expenses for items the company must have in
place each month for each customer.” This excluded such “customer-related costs” as
transformation and distribution plant. Pa. P.U.C v. West Penn Power Co., 59 Pa. PUC 552, 69
PUR4th 470, 521 (1985). OCA confirms that “More recently, the Commission affirmed its view
that the determination of “basic customer cost” should be limited to costs directly necessary to
customer service”. See, Pa. P.U.C. v. West Penn Power Co., 1994 Pa. PUC LEXIS 144, 154
(1994). OCA MB at 136
OCA witness Galligan calculated and proposed a more correct rate for rate RS,
and for the usage charges, which he opined were disproportionate and should be rejected. The
table below shows his proposed rate as compared to the existing rate and the Company’s
proposed rate:
Present Rate
PPL Proposed Rate
OCA Proposed Rate
Distribution Charge
$6.55
$12.20
$8.00
First 200 kWh
1.817 ¢ per kWh
0.000 ¢ per kWh
2.292 ¢ per kWh
Next 600 kWh
1.612 ¢ per kWh
2.198 ¢ per kWh
2.087 ¢ per kWh
Over 800 kWh
1.489 ¢ per kWh
1.879 ¢ per kWh
1.964 ¢ per kWh
Source: OCA St. 4 at 23, 25; OCA MB at 138
Witness Galligan calculated what he considered to be the correct customer charge
as follows:
Schedule RAG-4 shows the determination of PPL’s customer costs
eligible for inclusion under my understanding of Commission
precedent. In Pennsylvania, customer costs included in a monthly
fixed charge, such as PPL’s Distribution Charge, include return,
taxes on return, and depreciation on services plant and meter plant.
The return and taxes costs are $41.9 million, as shown on Schedule
RAG-4. Other fixed costs included in the Distribution Charge are
the $10.0 million and $6.3 million of depreciation expense on
services and meters plant. Also considering variable O&M costs
153
included in the Distribution Charge, as shown on Schedule RAG-4,
results in total Distribution Charge costs of $108.166 million.
Utilizing the costs shown on Schedule RAG-4, the calculated
monthly Distribution Charge would be $7.83.
A more
economically meaningful Distribution Charge price signal would
exclude the fixed costs, or depreciation expense and return and
taxes, from the Distribution Charge determination.
OCA St. 4 at 24-25; OCA MB at 136-137
OCA argues persuasively that the basic customer costs should be increased by
$1.45 monthly, and that an increase in the customer charge of 86% cannot be justified in this
proceeding. The ALJ agrees, and recommends that the Commission adopt OCA’s proposed
customer charge for rate RS of $8.00 a month.
OCA then takes on the inclusion of 200 kW in the customer charge and the
collapsing of the first rate block. Witness Galligan explains that this is a minimum bill concept.
Under this minimum bill, the customers would get no price signals for the usage of their first 200
kW. OTS witness Yarolin also opposes this concept. Not only does the first rate block
disappear, but the tailblock discount increases dramatically. Galligan proposes that the Company
keep the three block structure in addition to a customer charge that reflects customer costs as
defined by the Commission. His explanation of his rate design is set forth below:
The $1.45 Distribution Charge increase is slightly in excess of
customer costs calculated in accord with my understanding of
Pennsylvania Commission precedent on this issue. All other block
rate prices have been increased by the same absolute 0.475 cents
per kWh amount. Those proposed rates are consistent with PPL’s
current three-block rate design. PPL was granted its requested
authority to increase its rate blocks from two to three in its last rate
case. Continuity, stability, customer understanding and acceptance
suggest that PPL’s proposal to effectively eliminate its
Commission-approved additional rate block in order to
accommodate PPL’s inordinately large Distribution Charge
increase should be denied. The proposed, equal, absolute 0.475
cents per kWh increase is consistent with average, embedded cost
of service study results. These cost of service studies do not
determine costs by consumption level.
OCA St. 4 at 25.
154
OCA asserts that witness Galligan’s proposed rate design for rate RS should be
adopted in this proceeding. The ALJ recommends it to the Commission.
B.
Rate RTS Rate Design
OCA points out in a note that:
Rate RTS was a load management tool developed in the early
1980's and made available to customers who installed electric
thermal storage systems with timing devices that permitted PPL to
pre-set the time during which electric heat and/or hot water heating
occurs. Rate RTS is closed to new customers. Existing Rate RTS
customers receive grandfathered service for the life of their
thermal storage equipment. See, Pa. P.U.C. v. Pa. Power & Light
Co., 85 Pa. PUC 306, 400 (1995).
OCA MB at 139.
PPL does not propose a basic change to the existing rate design for residential
customers taking service under Rate RTS.
However, according to OCA, PPL is seeking to
move an excessive amount of costs into the Rate RTS customer charge. The Commission has
held that the customer charge should not be used to collect anything but basic customer costs.
The Company attempts to justify its proposed Rate RTS customer charge by arguing that the
current customer charge does not recover all fixed costs associated with serving a residential
customer. PPL St. 6-R at 13. According to OCA, “The Company’s proposed increase in the
Rate RTS customer charge should be rejected because it captures too many costs that are not
direct customer costs. Instead, OCA witness Galligan recommended that, for the sake of
simplicity, RTS customers receive the same $1.45 rate increase that he proposes for the 1.1
million Rate RS residential customers.” OCA witness Galligan proposes the following rates for
RTS customers:
Present Rate PPL Proposed Rate OCA Proposed Rate
Distribution Charge
$15.21
On-Peak kW in excess of 2 kW $0.90
$20.20
$16.66
$0.56
$1.25
Source: OCA St. 4 at 26.
155
OCA’s proposed rate design more accurately establishes a customer charge that
comports with Commission policy, and all residential customers would receive the same
customer charge increase in this proceeding. For these reasons, the OCA argues that its
proposed Rate RTS rate design should be adopted. The ALJ recommends it to the Commission.
4.
PLUG
PPL PLUG (PLUG) is an ad hoc group of governmental entities participating in
this proceeding to advance its members’ positions with respect to the ultimate allocation of
PPL’s proposed rate increase for its distribution and transmission functions. As far as the ALJ
knows, this is the first appearance of this group before the Commission. PLUG members in this
proceeding are: City of Harrisburg, Dauphin County; Hampden Township, Cumberland County;
Derry Township, Dauphin County; Borough of Steelton, Dauphin County; Borough of
Hummelstown, Dauphin County; Pennsylvania Turnpike Commission. PLUG MB at 1-2;
Appendix B. PLUG presented the testimony of three witnesses: John E. Bradley, Jr. PLUG Sts
1 and 1-R; Joseph V. Link, PLUG Sts 2 and 2-R, and Michael G. Musser, II, PLUG St 3.
PPLEU’s street lighting customers use electricity to illuminate the highways,
streets and other public areas of communities. Although street lighting customers are served
under a series of tariffs, PLUG will use SL/AL as an abbreviation for street lighting service as it
is referred to that way in PPLEU’s supporting documents. PPLEU serves street lighting
customers under several tariff rates (SA, SE (energy only), SHS, SM, and SR-1), all of which are
consolidated for purposes of its cost of service study. SL/AL is unmeasured electric service. Flat
base rate charges are predicated on an estimated 43,000 hours of use per fixture, per year.
Traffic signal lighting is also a public service that is provided by many PLUG
members. Unlike street lighting, the vast majority of traffic signal lighting is not served under
separate rate classifications. PPL includes traffic signal lighting in its general service class.
PLUG MB at 2.
156
PPL’s filing would increase SL/AL rates by 9.9% (on a “total bill” basis); the
increase for distribution is 11.9% of existing revenues or $2,100,000. Transmission rates would
be set at $0.00564 per kWh regardless of customer class, which amounts to more than a 75%
increase for SL/AL customers, or about $270,000. The SL/AL rate of return, expressed as a
percentage of system average rate of return, would escalate from 26% to 31% under PPL’s
proposal. PPL’s articulated goal in allocating rates based on the “total bill” increase was to limit
the combined rate increase to no more than 10% of each customer classes’ average bill.
PLUG MB at 3
PLUG submits that there are a number of persuasive and independent reasons
why SL/AL rates should not increase at all. They are that: (1) street lighting is a
public good or benefit that should not have to bear its fully allocated costs of
service; (2) the quality of the service that SL/AL customers have been receiving
and currently receive from PPL is inferior to that received by other classes and
that quality of service should be reflected in the allocation of costs to SL/AL
customers; and (3) street lighting service is more comparable to interruptible
service than firm service and should be priced accordingly.
PLUG MB at 3
Traffic Lighting
The Company responds:
Within PPL Electric’s territory, traffic lighting service is metered and
provided under Schedule GS-1. In this proceeding, representatives of three local
governments – John Bradley (Manager of Hampden Township, Cumberland
County); Joseph Link (City Engineer, City of Harrisburg, Dauphin County); and
Michael Musser (Manager, Borough of Steelton, Dauphin County) testified as
members of the PLUG, proposing that PPL Electric’s tariff be changed to offer
unmetered service for traffic signals. PLUG St. 2, p. 5; see also PLUG St. 1, p. 6.
PPLEU MB at 170
PLUG has offered no specific rates for such unmetered service, but
contends that because traffic signal usage is “consistent and ascertainable,”
metering is unnecessary and imposes avoidable costs. PLUG St. 2 at 3, 5.
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PLUG’s primary justification for its proposal is the possibility of installing LEDs
to replace incandescent traffic lights. PLUG St. 2, p. 3. PLUG members are
essentially proposing that PPL Electric now remove all of its meters from traffic
lights – meters which measure actual usage and permit PLUG members to directly
realize savings from any LED lights – in favor of an unmetered rate that would
preclude direct realization of savings for municipalities which undertake
conservation measures.
PPLEU MB at 172
The Company has considered unmetered rates for traffic lighting before, and
concluded that “such service presents difficult issues regarding electric usage and is
administratively complex.” The company maintains that traffic signal and usage can be quite
varied and complex, and that even where equipment appears to be similar, usage can vary
substantially, and that the administrative complexity of unmetered traffic service is also
substantial. It also argues that the costs could be substantial. PPLEU MB at 171-172
PPLEU argues that the Commission should reject PLUG’s proposal for unmetered traffic
lighting service. However, the ALJ favors PLUG’s intention to expand the use of LED traffic
signals in this area as energy saving and efficient, and recommends that the Commission
encourage PPLEU to cooperate with this effort.
Street Lighting
PLUG makes two basic arguments that it should receive no increase at all, or a
greatly reduced one. First it asserts that street lighting is a public good, and second it contends
that service is so poor that it should be billed as an interruptible service at best.
PPLEU summarizes the “public good” position as follows:
Mr. Bradley argues that the streetlight class should not have to pay more
than 25% of its allocated costs because streetlights provide a “public good” and
therefore should be afforded the same treatment as fire hydrants under the Public
Utility Code. See 66 Pa. C.S. § 1328 (limiting utility charges for fire hydrants to
25% of allocated costs). Mr. Bradley’s analogy is misplaced: a streetlight
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operates every night and consumes energy delivered by PPL Electric’s
distribution system, throughout the year, while fire hydrants operate only at times
of fire. Tr. 1078. In any event, the legislature has not seen fit to provide such
equivalent benefits to municipalities for street lighting, and the Commission
should not infer such a benefit where none now exists.
PPLEU MB at 174.
PPLEU argues that street lighting is not a public good in the same category as fire
hydrant service or volunteer fire company service, which is granted this status in statute, and
receives limited increases under that statute. The ALJ acknowledges that street lighting is not
included in that statute, nor is it so defined in any other statute. Nonetheless, she opines that
street lighting is a public good. The Company’s SL/AL customers do not consume electricity for
their own direct benefit—they consume it to provide lighting for citizens on the streets and
public areas , and to assist the police and fire men and women in performance of their duties to
protect the public. This is not in the same category as many other municipal services which are
part of the duties of government, such as voter registration, or tax collection. However, she
agrees that there is not a basis to limit SL/AL to a 25% increase.
The Company argues that:
Under present rates, municipal customers receiving service under PPL
Electric’s street lighting schedules pay only a 1.6% rate of return, which is less
than half of the present average system rate of return of 3.91%. Ex. JMK1,
Section 2, p. 8; PPLICA St. 1, p. 34. Assuming PPL Electric receives its full rate
increase in this proceeding and costs are allocated as proposed by PPL Electric,
street lighting rates would be increased by 9.9%. However, street lighting
customers would still be paying a rate of return of only 2.76%, or slightly less
than one-third of the system average rate of return of 8.8%. Ex. JMK7, Section 2,
p. 8.
PPLEU MB at 173
The ALJ cannot recommend to the Commission that this increase is too high under the present
circumstances.
159
The Company included a summary of PLUG testimony as the basis for part of its
argument:
Messrs. Bradley, Musser, and Link of PLUG also testified regarding street
lighting in their municipalities, contending that PPL Electric’s proposed increase
for unmetered street lighting service under Rate Schedules SE, SHS, and SM
would be a burden or otherwise reduce municipal resources. Mr. Bradley of
Hampden Township further testified that he was experiencing problems with the
time PPL Electric took to replace non-functioning street lamps, and that he
believed PPL Electric should inspect streetlights in its territory and not wait for
municipalities to report that a light was out. Both Mr. Bradley and Mr. Musser
proposed that PPL Electric should provide municipalities with “outage credits” if
PPL Electric does not replace a light after being told it was not functioning.
PLUG St. 1, p. 3-5; PLUG St. 2, p. 2-3; PLUG St. 3, p. 3.
PPLEU MB at 172
The Company argues that the evidence at hearing failed to establish that the
Company’s service was so poor as to be considered as to be interruptible, or to show that PPLEU
should maintain street patrols to look for street lights that are out. PPLEU MB at 173. PPLEU
owns many street lights, but some municipalities own their own street lights, and purchase
unmetered service for those lights. These two kinds of service cannot be lumped together.
The ALJ agrees that the Commission should reject PLUG’s proposals.
X.
1.
UNIVERSAL SERVICE AND CUSTOMER/COMMUNITY PROGRAMS
INTRODUCTION
Universal electric service is well-defined under Pennsylvania law. The Public
Utility Code contains a specific definition applicable to all electric distribution companies,
including PPL Electric:
“Universal Service and energy conservation. Policies,
protections, and services that help low-income customers to
maintain electric service. The term includes customer assistance
160
programs, termination of service protection and policies and
services that help low-income customers to reduce or manage
energy consumption in a cost-effective manner, such as the lowincome usage reduction programs, application of renewable
resources, and consumer education.”
66 Pa.C.S. § 2803. The Public Utility Code requires the Commission to ensure that programs for
universal service and energy conservation are appropriately funded and available in the territory
of each electric distribution company through non-bypassable, competitively neutral costrecovery mechanisms that fully recover the costs of such programs. See 66 Pa.C.S. § 2804(9);
52 Pa. Code § 54.72. PPLEU MB at 134
The Company’s witness on these issues is Timothy R. Dahl (Dahl), who
submitted testimony at PPLEU St 7 and 7-R. Dahl avers that the Company has been an industry
leader in these programs for 20 years, and that judged against the statutory standards of helping
low income customers maintain electric service:
PPL Electric has the most successful universal service program in
Pennsylvania, with the lowest termination rate of jurisdictional
electric and gas utilities in Pennsylvania for all residential
customers (0.68 percent), and a similarly low termination rate for
low-income residential customers (3.2 percent). PPL Electric St.
7-R, p. 15; Tr. 758; OCA St. 5, p. 12. Residential customers
served by other Pennsylvania electric utilities are, on average, two
and a half times more likely to have their service shut off for nonpayment than a residential customer of PPL Electric. PPL Electric
St. 7-R, p. 15.
PPLEU MB at 134. No party has challenged the efficacy of the Company’s programs in this
regard, although two parties, OCA and CEO, want expansions of certain aspects of the programs.
In this proceeding, PPL Electric proposes to continue and expand its universal
service and customer/community programs as described below:

An increase of 25.6% in funding for OnTrack, PPL Electric’s customer assistance
program, permitting enrollment of up to 17,000 low-income customers;
161



An increase of 17.5% in funding for weatherization and
conservation through PPL Electric’s Winter Relief Assistance
Program (WRAP), with further expansion of the Company’s
program in solar water heating installation;
Continuation of Operation HELP, PPL Electric’s hardship
fund, which has provided over $13.5 million to more than
52,000 customers in the past twenty years and is funded
entirely by the Company’s shareholders and voluntary
contributions by PPL Electric employees and customers;
Introduction of a new community betterment initiative (CBI),
funded jointly by PPL Electric shareholders and ratepayers, to
help communities leverage matching state funds for targeted
programs in economic development and affordable housing in
the Company’s service territory.
PPLEU MB at 135.
OTS and OCA challenge the funding proposed for OnTrack and Wrap; OCA
challenges the entire funding method for universal service programs; OCA also suggests several
minor improvements and one major change to OnTrack; CEO proposes major increases in
enrollment, and more inclusive methods of working with CBOs. PPLEU, PPLICA, and OSBA
are all opposed to OCA’s reallocation of funding for these programs. The Company in fact
resists all suggestions to change its proposals, saying:
The programs offered by PPL Electric and its proposals in this
proceeding, ...are based upon the Company’s decades of
experience working with low-income customers and community
organizations and its commitment to proper use of ratepayer funds.
PPL Electric St. 7-R at 33-34.... The Commission should approve
PPL Electric’s universal service and customer/community program
proposals, and reject the alternatives offered by opposing parties.
PPLEU MB at 135
OCA gave PPLEU’s proposals a most thorough evaluation, and OCA witness
Colton made a series of recommendations:
1) place identified low income customers in arrears on an “opt
out” standard payment plan consisting of a budget bill and an
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arrearage payment equal to the average payment under the Bureau
of Consumer Services guidelines for the customer’s income level;
2) implement an outreach program to ensure that low income
customers with wage income apply for the federal Earned Income
Tax Credit (“EITC”) and other applicable tax credits;
3) clarify its brochures and rules for the On-Track program so that
customers and Community Based Organizations (CBOs) properly
understand the program requirements; and
4) develop a plan to increase hardship fund contributions to
Operation HELP from customers, employees, shareholders and the
community.
5) supported PPL’s proposed Community Betterment Initiative
and recommended that the affordable housing component focus on
energy efficiency partnerships.
OCA MB at 155.
2.
FUNDING FOR ONTRACK AND WRAP
OCA has summarized this issue admirably, and the ALJ quotes the OCA analysis
and results below:
PPL has proposed to include in rates a normalized level of
funding for its On-Track and WRAP programs since it is proposing
to expand these programs over a number of years. Under PPL’s
proposal, PPL would normalize the costs of these programs based
on its budgets for the period 2005 through 2011. PPL St. 7 at 12.
This means that more dollars will be included in rates in the early
years than what the Company will spend, and less will be included
in rates in the later years than what the Company will spend. PPL
St. 7 at 12. While the OCA does not disagree with the
normalization approach, particularly as a program is being ramped
up in size, the OCA disagrees with the Company’s proposal to
normalize the universal service expense over such an extended
period of time, particularly since the Company anticipates further
distribution base rate proceedings in this time period. OCA St. 5 at
37. The OCA recommends that a two-year period be used for this
normalization in that this reflects the Company’s own testimony as
to when it anticipates another base rate filing, and it reflects a more
reasonable planning horizon. Id. The effect is a $1.9 million
reduction in the Company’s claimed expense in this proceeding.
Appendix A, Table II. It is important to note that the OCA’s
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proposal will result in the inclusion in rates of the amount of
dollars that the Company proposes to spend on its universal service
programs for 2005 and 2006, on a normalized basis. Tr. at 480-81;
859-60. The future need for additional funding from ratepayers for
the program should be taken up in the next expected base rate case.
Tr. at 860.
OCA MB at 173
The ALJ recommends this approach to the Commission. If the Commission
accepts the Company approach, the ALJ recommends that the Commission direct the Company
to establish interest-bearing escrow accounts, with the escrow interest to be included in ratepayer
funds for these programs when the account is used.
.
OnTrack
PPLEU introduces one of its primary customer aid program as follows:
OnTrack [is the Company’s] customer assistance program
(CAP) to help low-income, payment troubled customers maintain
electric service through reduced payment plans and arrearage
forgiveness. See 52 Pa. Code §§ 54.71-72; PPL Electric St. 7at 4.
The current annual funding level from ratepayers for OnTrack –
$11.7 million – was established in the settlement of PPL Electric’s
1998 restructuring case. PPL Electric St. 7 at 11-12. Since the
restructuring settlement agreement, the Company has spent $47.6
million on OnTrack, or 101% of the required funding. PPL
Electric St. 7-R at 11. At the end of 2003, there were 12,420
customers enrolled in OnTrack. PPL Electric St. 7 at 8.
PPLEU MB at 136.
The Commission reviewed the Company’s most recent Universal Service and
Energy Conservation Plan and concluded that the Company should have no less of an enrollment
number of 17,000. See Re: PPL’s Universal Service and Energy Conservation Plan Submission
in Compliance with 52 Pa. Code § 54.74, Docket No. M-00031698 (June 12, 2003). CEO CrossExamination Ex. 1 at 15. PPLEU MB at 17-18. Also, the Company obtained a neutral thirdparty organization evaluation of the program, which estimated that the market of likely on Track
participants was about 30,000 customers. However, the Company’s experience is that one out of
164
every two customers approached by various means of outreach eventually enrolls in the program.
This evaluation indicates an enrollment goal of 15,000 to 17,000.
In this case, PPL Electric has proposed a 25.6% annual increase in OnTrack
funding -- from $11.7 million to $14.7 million:
This increased funding will permit a total OnTrack enrollment of
approximately 15,000 to 17,000 customers by 2007. PPL Electric
St. 7 at 13; Tr. 724. Consistent with the procedures used to
implement the 1998 restructuring settlement agreement, the
Company has proposed that this $3 million OnTrack funding
increase be “ramped up” by increasing annual spending by $1
million per year through 2007, with the difference in ratepayer
funds collected and spent in 2004-07 escrowed to permit higher
expenditures ($15.7 million instead of $14.7 million) in the years
2008-2010. PPL Electric St. 7, p. 12.
PPLEU MB at 136. The ALJ has recommended that this amount be normalized. This should be
sufficient to comply with the Commission Order and respond to the evaluation report.
No party has objected to an increase in funds, other than normalization, for
enrollment for OnTrack. However, CEO contends that PPLEU’s proposed increase is not large
enough, and requests more money from ratepayers to enroll up to 100,000 more customers.
However, CEO does not document the need for 100,000 more enrollees, and does not specify the
amount of additional funding that will be needed to support them in the program. The Company
argues that CEO’s proposals are too vague and ill-defined to be adopted by the Commission. For
example:
...representatives of CEO testifying in this proceeding could not
even agree among themselves regarding a preferred level of
enrollment. Eugene Brady, the Executive Director of CEO,
proposed that PPL Electric should enroll 50% of estimated lowincome customers (or 100,125 customers). CEO St. 1, p. 8; PPL
Electric St. 7-R, pp. 12-13. However, John Howat, a
representative of the National Consumer Law Center testifying on
behalf of CEO, identified a low-income population of
approximately 114,000 customers, and proposed that PPL Electric
165
should serve 35% of that population (39,900 customers). Id.; CEO
St. 2, p. 12; Tr. 869-70 (proposing 35% instead of 50%).
The ALJ agrees with the Company, and recommends that the Commission
approve PPLEU’s enrollment goal, and reject that proposed by CEO.
Wrap
The Company seeks to continue and expand its Winter Relief Assistance Program
(WRAP) which provides free weatherization measures and energy conservation services to lowincome customers. PPLEU MB at 143
Once again, CEO finds PPLEU’s proposed increase in funding and goals wanting.
The Company has proposed a $1 million increase in WRAP with implementation of solar water
heating as a standard WRAP measure, based on PPLEU’s successful Solar Water Heating Pilot
Program. CEO seeks $1.3 million increase in funds, with $1 million dedicated to solar water
heating, and an increased participation of CBOs in the WRAP program design.
Once again, the Company urges the Commission to reject CEO’s demands. Once
again, the ALJ agrees. PPLEU presented evidence that its pilot program in solar heating
identified substantial challenges in locating and installing solar water heating in WRAP
participant homes. CEO addresses none of the complexities of actually accomplishing
installations. Likewise, CEO presented no evidence that there is a pressing need for increase
CBO involvement by WRAP delivery agencies in designing WRAP delivery elements. PPLEU
avers that it works closely with its weatherization contractors and conducts regular meetings on
many issues, and will continue to do so. PPLEU MB at 144-145
The Company stated that “Epstein also expressed concern that WRAP funding
was declining and that the Company’s WRAP administrative costs were almost 20%. Epstein at
24. In fact, the Company has proposed to increase WRAP funding and administrative costs are
kept at or below 15%.” PPL Electric St. 7-R at 27.
166
The ALJ recommends the Commission accept the PPLEU proposal, subject to the
OCA amortization adjustment.
3.
$150 ARREARAGE ELIGIBILITY REQUIREMENT FOR ONTRACK
The Company introduces this disputed issue as follows: “In order for a lowincome customer to be eligible for the OnTrack program, PPL Electric requires that the customer
have an overdue balance of at least $150. PPL Electric St. 7-R at 16-17. CEO has proposed that
this requirement be eliminated because CEO contends that it discriminates against low-income
customers, particularly the elderly, who pay their electric bills in full, and may encourage
outstanding balances to accrue.” CEO St. 1 at 8; CEO St. 2 at 12-13. PPL Electric disagrees
with CEO. PPLEU MB at 139
PPL Electric imposed the $150 arrearage requirement as a means to ensure that
the limited resources of OnTrack are directly targeted to those customers who are most
vulnerable to imminent termination of service. The Company initiates collection efforts (e.g.,
transmittal of a termination notice) when a residential customer reaches $150 in arrearages. Tr.
729-30; see also 66 Pa.C.S. § 2803(4) (defining universal service to include protections that help
low-income customers to maintain electric service). Id.
For the Company, “This arrearage requirement has [long] functioned as a key
indicator of vulnerability and susceptibility of a customer to termination of service for nonpayment, whether that customer is elderly or not, thereby permitting PPL Electric to match
customer enrollment levels with available funding resources.” PPL Electric St. 7-R at 16; Tr.
730. The ALJ surmises that, understandably, CEO might wish for more flexibility from the
Company so that CEO could get assistance when people in need come to them seeking
assistance. However, PPLEU points out that CEO has provided no analysis to show the effects
of its proposal on enrollment or funding requirements for OnTrack, nor has CEO shown that the
$150 arrearage requirement does, in fact, encourage low-income customers to accrue outstanding
balances to become eligible for OnTrack.
167
The ALJ therefore recommends that the Commission permit the Company
to retain the $150 arrearage requirement to ensure that OnTrack resources are directed to those
customers most at risk for termination.
4.
MANDATORY OR PROACTIVE BUDGET BILLING PROGRAM
OCA witness Colton has become concerned with “the growing problem of
identified low-income customers who have arrears, often large arrears, but do not contact the
Company to enter into payment plans to address these arrearages.” OCA MB at 159. Colton
testified that “the average arrearage for a low income customer not on a payment plan has grown
from $318 in 2001 to $528 in 2003, even though the average bill for low income customers has
remained about the same.” OCA St 5 at 11
Colton asserts that the growing arrearages impact the Company’s finances, and
gave evidence that PPL is seeing increases of both low-income customers in arrears and the
arrearage amounts. He argues that this impacts the Company’s revenues and its need to expend
resources on credit and collection activities. OCA MB at 160. Further:
OCA witness Colton identified several concerns that could affect
the availability of the OnTrack program for customers.....The
Company targets low income customers that have broken at least
one payment plan and have an arrearage of at least $150. OCA St.
5 at 8. However, only a small portion of the PPL customers are on
payment plans even though they have significant arrears. Without
having been on a payment plan, a low income customer, even a
customer with high arrearages, is unable to qualify for On-Track
assistance. Second, Mr. Colton found that the growing arrears of
the low income customers that are entering the program make the
program more expensive as these large arrears become part of the
cost of the program. As this cost grows, fewer customers will be
able to be served within the budgets provided for the program.
OCA St. 5 at 17-18.
OCA MB at 158
168
In response, OCA witness Colton has designed what he calls an “opt-out”
standard payment plan (also referred to as mandatory budget billing or opt out budget billing) for
all identified low income customers who are in arrears, but not on payment plans.
The standard payment plan would consist of two components:
1)
2)
an opt-out budget billing component for current bill
an arrearage payment equal to the average payment
required under the BCS informal payment plan guidelines
for their income level.
OCA St. 5 at 14. If the customer did not wish to be on this standard payment plan, the customer
would contact the Company to negotiate an alternative plan. OCA expects the customers to pay
their bills and outstanding arrearages with the federal Earned Tax Income Credit (EITC), and
recommends that the Company implement a program that helps their customers to obtain them.
PPLEU MB at 14030
The Company is not in favor of this plan, and in fact is strongly opposed to it.
The normal May bill for actual usage is about $45.00, and OCA is recommending that the
Company present these customers with a bill of about $200.00 (Budget of $165.00 plus payment
on arrearages). The Company does not think that just putting a payment troubled customer on a
budget plan unilaterally, without any prior agreement to enter a budget program, does anything
that makes it more affordable for them. Moreover, there is no guarantee that customers
unilaterally placed on a budget plan would use EITC to pay their electric bills, even if the
Company helped them get them. PPLEU argues that the studies relied on by OCA show that
only 1/3 of the recipients use them for back bills, and 75% do not use them for utility bills.
PPLEU MB at 140-142
30
The ALJ opines that the Commission precedent set in Mary Frayne v PECO Energy Company, C20029005, Opinion and Order entered September 10, 2003, OCA MB, Vol II, does not support this policy because
the customers in question will already have a payment plan set.
169
Under the OCA’s proposed program, PPL would
unilaterally switch an estimated 20,000 to 30,000 low-income PPL
Electric customers to budget billing, without their consent, and
send them an expectedly large May bill. The resulting protests
from those customers would undoubtedly increase costs and could
wreak havoc on PPL Electric and the Commission in the form of
complaints to the Commission and customer service expense
arising from customers upset about receiving higher bills and being
automatically placed on mandatory budget billing. Tr. 714; PPL
Electric St. 7-R at 15. [After the low-income customer is
“slammed” by being put on mandatory billing, the customer cannot
return to regular billing without entering into a payment
agreement, the violation of which could result in termination of
service.]
OCA attempts to minimize the costs of customer
dissatisfaction and suggests that angry customers calling PPL
Electric are preferable to no contact with customers in arrears.
OCA St. 5-R at. 2-3 & 7. OCA ignores the fact that PPL Electric
is already communicating with these customers regarding their
arrearages. Tr. 716-717. Sending customers an unexpected,
substantially higher bill is unlikely to result in any arrearage
reduction. The net result of the OCA’s proposal will be angry
customers and increased costs, not improved collections.
PPLEU MB at 142-143
OCA’s arguments against the Company’s position are not convincing. Essentially
OCA argues it is not an appropriate response to worry about customer satisfaction when those
customers owe the Company a substantial amount of money; that the Company showed no
evidence to support arguments about increased calls to the call center, and the cost of any
increase would be minimal, and would be offset by other cost savings. PPLEU MB at 164
The ALJ finds the Company’s position on this recommendation much more
persuasive than OCA’s. The Company has employees in the trenches working with collections
and payment-troubled customers, and has some knowledge of what will work and what will not.
There may be a need for a pro-active program, but this one is not it.
170
The ALJ notes that nonetheless, the Company has agreed to implement a pilot
EITC program to see if it can assist its customers in obtaining these benefits. PPLEU MB at 140
5.
OPERATION HELP’S FUNDING AND IMPLEMENTATION
PPL Electric’s Operation HELP program provides short-term financial assistance
to the Company’s customers who are experiencing difficulties paying their electric bills. Now in
its twenty-first year, Operation HELP is not funded through rates but through contributions from
PPL Corporation and voluntary contributions from PPL Electric employees and customers.
Through this program, over $13.5 million has been raised to assist 52,000 customers. PPL
Electric St. 7-R at 28. PPL Electric intends to continue this program, with a goal of $900,000 in
total contributions from PPL Corporation and donations from employees and customers. PPL
Electric St. 7 at 6; PPLEU MB at 145-148
As a legal matter, no portion of Operation HELP funding is included in rates, and
the Commission cannot order an increase in voluntary contributions by PPL Corporation or PPL
Electric’s employees and customers. Cf. Re Pennsylvania-American Water Company, 231
P.U.R. 4th 277, 315 (2004) (explaining that “[q]uite simply, the Commission is without authority
to require PAWC, or any public utility, to either make or increase contributions derived solely
from shareholder funds”). Operation HELP is beyond the Commission’s jurisdiction, and there
is no legal basis to require PPL Electric to file a plan with the Commission for a program over
which the Commission has no control. PPLEU MB at145-148
The ALJ agrees that the Commission has no jurisdiction over Operation Help
since it is privately funded and is not included in rates. Therefore she will not take the
Commission’s time discussing OCA and CEO proposals regarding it. Both OCA and CEO
ignore the jurisdiction issue in their Reply Briefs. However, the ALJ points out that the reason
Operation Help came up in this case is that the Company witness voluntarily, in direct testimony,
described it as one of the Company’s four major universal service programs. Since it is not in
rates and is privately funded, the ALJ questions its relevance to this case, unless it was necessary
to give the whole picture.
171
The ALJ recommends that the Commission reject both the OCA and CEO’s
proposals with regard to Operation Help.
6.
COMMUNITY BETTERMENT INITIATIVE (CBI)
PPL Electric proposes to introduce a Community Betterment Initiative (CBI)
designed to assist community development organizations and human services agencies in
meeting local needs by leveraging matching funds from the state for targeted programs in
economic development and affordable housing. PPL Electric St. 7, at 17-18. PPL Electric has
proposed an initial funding of this program for three years, with an annual contribution of $1
million from PPL Corporation shareholders and $1 million from ratepayers. Effectiveness of the
program will be reviewed in 2007. Id. PPLEU MB at 148
According to OCA, the CBI can provide benefits to ratepayers, similar to those
provided by the Company’s Weatherization program, particularly if the affordable housing
component operates to leverage state funding to help implement energy efficiency investments in
affordable housing. OCA MB at 171
According to OTS “The Company is attempting to fund a social program through
ratepayer funds. As no direct benefit to ratepayers has been established, this claim [for $1
million of ratepayer funds] must be denied.” OTS MB at 27-2831. US DOD also objects, saying
that the customers should make their own decisions with respect to social or charitable programs.
The Company denies that this is a social or charitable program, and asserts to the contrary it is
OTS argues that this proposed program is illegal: “This Commission has consistently found that a
utility must identify a direct benefit to ratepayers in order to recover an expense for ratemaking purposes. This was
correctly stated in the Company’s last base rate case found at Docket No. R-00943271. See also, Pennsylvania
Public Utility Commission v. Consumers Pennsylvania Water Company – Roaring Creek Division, 87 PA PUC 826,
841 (1997). The Company has stated that it will not contribute anything to this initiative unless the Commission
requires ratepayers to contribute. PPL has sought to enhance its own community image, but only if ratepayers are
forced to contribute. The Company’s lack of conviction and the absence of a benefit to ratepayers are sufficient
reasons to reject this claim. Similar claims were rejected in the Company’s last base rate case. The removal of this
expense claim [would reduce] the Company’s operating expenses by $1,000,000.”
31
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designed to facilitate access to existing state economic development funds that rely on
public/private partnerships. PPLEU MB at 149
The CEO wants to have the program restructured to implement a formal review
process of CBI fund allocation with input from all relevant stakeholders. The Company argues
that this imposes significant risks for creating conflict of interest as well as administrative
impracticalities. The Company assures the Commission:
In implementing CBI, the Company fully intends to conduct a
grant process that ensures equal opportunity for applicants and is
consistent with the community economic development strategies in
which local non-profit organizations have had an opportunity to
participate. Id.
The ALJ recommends support of CBI.
7.
REQUESTS TO REALLOCATE UNIVERSAL SERVICE PROGRAM COSTS
The OCA seeks to have the Commission reallocate the costs for Universal Service
programs across all customer classes, instead of allocating them only to the residential classes.
Epstein seeks to have them allocated in part to PPLEU’s shareholders.
The Company asserts that according to several provisions of the Public Utility
Code, universal service costs must be paid by the Company’s customers, and therefore cannot be
allocated to shareholders.
In Section 2804(8) of the Public Utility Code, the
Commission is specifically directed “to establish an appropriate
cost recovery mechanism which is designed to fully recover the
electric utility’s universal service and energy conservation costs
over the life of these programs.” 66 Pa.C.S. § 2804(8). Section
2804(9) further specifies that the programs are to be funded “by
nonbypassable, competitively-neutral cost-recovery mechanisms
that fully recover the costs of universal service and energy
conservation services.” 66 Pa.C.S. § 2804(9).
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PPLEU MB at 152
The ALJ notes that neither of these provisions directly mentions recovery from
customers or ratepayers. The Company asserts that Epstein does not provide any legal basis for
his request that the Commission direct PPL shareholders to fund PPL Electric’s universal service
programs, and his request should be denied. The Commission does not have direct jurisdiction
over the Company’s shareholders.
The OCA includes a learned and lengthy section in its Main Brief based on
provisions of the statute, 66 Pa. C.S. §§2804(9), 2802(17), and evidence provided by witness
Colton to support the proposition that PPLEU’s universal service programs benefit all customers,
and therefore program costs should be allocated across all customer classes32. OCA MB at 174186. However, the ALJ is not persuaded by these arguments.
The Company responds very simply in both its Main and Reply Briefs that OCA
has not shown any basis to change established Commission policy to allocate costs of universal
service programs to residential customers who may benefit directly from the programs, into
32
Section 2804(9) of the Public Utility Code reads as follows:
(9) The commission shall ensure that universal service and energy conservation
policies, activities and services are appropriately funded and available in each
electric distribution territory. Policies, activities and services under this
paragraph shall be funded in each electric distribution territory by
nonbypassable, competitively neutral cost-recovery mechanisms that fully
recover the costs of universal service and energy conservation services. The
commission shall encourage the use of community-based organizations that
have the necessary technical and administrative experience to be the direct
providers of services or programs which reduce energy consumption or
otherwise assist low-income customers to afford electric service. Programs
under this paragraph shall be subject to the administrative oversight of the
commission which will ensure that the programs are operated in a cost-effective
manner.
Section 2802(17) reads:
(17) There are certain public purpose costs, including programs for low-income
assistance, energy conservation and others, which have been implemented and
supported by public utilities’ bundled rates. The public purpose is to be
promoted by continuing universal service and energy conservation policies,
protections and services, and full recovery of such costs is to be permitted
through a nonbypassable rate mechanism.
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allocating these costs across all customers. OCA in its testimony develops the concept that these
programs are a public good, but the Company asserts that this is not and should not be the basis
for public utility cost allocation. The Company also argues that the OCA did not make any
proposal to allocate these costs. The Company concludes that:
In any event, the Commission previously has rejected
proposals to allocate PPL Electric’s universal service costs to other
rate classes to avoid cost shifting. See Re: Pennsylvania Power &
Light Company, 89 Pa. PUC 587, 658 (1998) (rejecting proposal to
reallocate universal service costs in PPL Electric’s restructuring
proceeding). The Commission should continue allocation of these
costs to PPL Electric’s residential class, consistent with other
Commission decisions.
PPLEU MB at 153.
However, the Customer Choice Act specifically forbade shifting any costs in that proceeding. In
this proceeding, the Commission can look at shifting some of those costs if it wants to.
PPLICA and OSBA argue vigorously that any shifting of universal service
program costs would be completely inappropriate. OCA witness Colton argues that the term
nonbypassable used in the statute means that all customer classes must be allocated USP costs.
PPLICA argues to the contrary that this means that in an industry structure where customers
have the opportunity to access competitive supply, nonbypassable charges apply to both
shopping and non-shopping customers. PPLICA also argues that traditional rate making
concepts have not been thrown out the window by restructuring, and allocation by cost causation
is still viable. It argues further that since only residential customers can use USPs and any direct
benefits from these programs flow primarily, if not only to them, these costs must be allocated to
residential customers. Finally, PPLICA argues that USPs are not “public goods” like fire
hydrant service, and volunteer fire companies for which the Legislature has enacted special
ratemaking treatment, and that the NRRI definition relied on by witness Colton does not support
his argument. PPLICA RB at 32-35
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The ALJ agrees with the Company, PPLICA and OSBA that OCA has not
presented sufficient basis to change the Commission’s policy to allocate universal service costs
across all customer classes.
XI.
RETAIL COMPETITION ISSUES
Only one party participated solely and specifically to raise issues related to retail
competition, namely Strategic Energy, L.L.C. (Strategic). Strategic sponsored one witness,
James McCormick (McCormick), who gave testimony and sponsored a series of exhibits.
Strategic St 1, Strategic Exhs. 1-6.
McCormick described Strategic as follows:
Strategic Energy, based in Pittsburgh, Pennsylvania, is a competitive retail
provider of electricity and serves a peak load of approximately 3,300 MW with
approximately 50,000 customers in eight states. Strategic is licensed by the PUC
to provide electric supply and related services to residential, commercial,
industrial and governmental customers throughout Pennsylvania.
Strategic St 1 at 2-3
He further testified that Strategic’s interest in this proceeding is:
Strategic Energy is actively serving commercial load and actively
marketing in PPL’s service territory. We compete against PPL’s POLR service
and, to the extent that PPL’s distribution rates include the types of generationrelated retail customer care and overhead costs that Strategic incurs in its
competitive supply prices, our customers will pay for costs they do not impose on
PPL. This adversely affects our ability to compete. In view of the minimal level
of shopping in PPL’s territory, Strategic seeks to ensure that the Commission
adopts measures in this case that may help to increase retail competition in PPL’s
market.
Id.
In this proceeding, Strategic addresses proposals that would promote competition
in PPLEU’s territory: corrections for cost misallocations perceived by Strategic reflected in
PPLEU’s rates; installation of advanced meters and the Company’s automated meter reading
system; acceleration of availability of information from this system to competitive suppliers; use
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of the existing AMR system to provide more detailed customer usage information to competitive
suppliers on a regularly updated and refreshed basis; and, EGS consolidated billing. Strategic St
1 at 3
Strategic asserts that PPLEU improperly includes generation-related costs
associated with uncollectible accounts, customer care and overhead costs in distribution expense,
and thus in distribution rates, and proposes that the Commission direct PPL Electric to exclude
such costs. Strategic avers that these costs are also included in its rates as a competitive supplier,
and that PPLEU’s distribution rates are too high, and that Strategic’s customers have to pay
twice for such services.
Strategic avers that PPLEU’s distribution rates are unjust and unreasonable in that
they do not exclude generation related costs. Strategic cannot quantify these amounts, but states
the there is no doubt that they are there, and wants the Commission to require that PPLEU
identify them. In the alternative, Strategic urges that the Commission provide a discount to the
distribution rates through a competitive retail customer credit (CRCC) which has been developed
in New York state. Strategic St 1 at 5-6
PPLEU responds that this would violate the bases of the Joint Settlement
Agreement in the Restructuring case, PPL St 5-R at 20, and the rate caps established there:
These costs are directly tied to PPL Electric’s obligation to serve all
customers as an electric distribution company, regardless of customer payment
history, and are thus properly included in distribution revenue requirements. PPL
Electric St. 5-R, p. 20. In effect, through this proposal, Strategic seeks to readjust
the 1998 rate caps, and to preclude PPL Electric from recovering it’s prudently
incurred costs associated with uncollectible accounts.
PPLEU MB at 157. Therefore, it asserts that this request should be rejected.
In addition, Strategic offers a wide variety of proposals that it contends will
promote retail competition in PPL Electric’s territory, and asks that the Commission direct PPL
Electric to:
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(1) accelerate its AMR deployment;
PPLEU argues that any acceleration of the enhancements to its newly installed
AMR system would be unjustified at this point in time. The Company asserts that it has been
devoting substantial resources to deployment of this new system, and that it fully intends to
pursue appropriate enhancements. PPLEU St 4-R at 43. The Company also avers that it is
working closely with the Commission and stakeholders in various Commission collaboratives to
define future metering and data requirements that will be applicable when the generation cap is
removed in 2009. The Company does not want to get out of step with these efforts.
(2) provide EGS’s with an updated Eligible Customer List and distribute related “optout” cards to customers;
The Company testified that this list was part of its pilot program, and that it no
longer keeps this list, and that moreover, usage data associated with that list are now available
under other procedures. PPLEU St 4-R at 45-46. It argues that therefore, this request should be
rejected.
(3) accept an EGS’s telephonic representation that a customer has authorized release of
customer information;
The ALJ opines that this can possibly to lead “slamming” customers, that is to
change their electric suppliers without their knowledge or consent, which has allegedly occurred
in other competitive utility markets. PPLEU believes that:
This is inconsistent with customer privacy rights recognized by the
Commission. PPL Electric St. 4-R at 47. The Company’s long-standing
practice of requiring verifiable means to evidence a customer’s desire to
have its usage information provided to a third party was developed in
response to the concerns of a significant number of customers. Id. at 4748. While PPL Electric does not believe these verification components of
its procedures should be changed, the Company continues to adapt these
procedures to reflect new technologies consistent with customer privacy.
Id. (discussing e-mail and Web-based procedures).
PPLEU MB at 158. PPLEU urges that this request also be rejected.
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(4) provide EGSs with consolidated billing.
The Company “has already completed much of the design work and some of the
necessary modifications to its billing system, with about 10 months of time to complete the
system modifications” to deploy consolidated billing. Further,
PPL Electric stands by its original commitments to work with any EGS that
wishes to employ consolidated billing functionality, and to complete EGS
consolidated billing upon a reasonable demonstration that ratepayer money will
be spent on functionality that will be useful to customers. PPL Electric St. 4-R,
pp. 47-48.
PPLEU MB at 159. The Company asserts therefore that no further Commission directives are
needed in this regard.
The Commission’s policy and statutory mandate is to encourage retail
competition in the restructured electric utility industry, and the ALJ follows this policy and
mandate. The ALJ acknowledges Strategic’s, or any EGS’, right to access PPLEU’s customer
system information on the same terms as the Company has for itself. The ALJ relies on
PPLEU’s testimony that customer information is available under procedures other than the Pilot
Program list, PPLEU St PPLEU St 4-R at 45-46. She does not recommend that the Commission
direct the Company to redesign its distribution rates in violation of the Rate Structure Settlement
agreement, or accelerate deployment of special feature and programs for its AMR deployment
program, and definitely rejects Strategic’s request to have access to customer information on
telephone request alone. She opines that PPLEU’s combined billing efforts are near conclusion,
and agrees that no Commission directives are necessary at this time.
Therefore, the ALJ recommends that all of Strategic’s requests be rejected.
XII.
PUBLIC INPUT HEARINGS
A total of nine public input hearings, including afternoon and evening sessions,
were held between June 28, 2004, and August 13, 2004, in locations throughout PPL Electric’s
service area: Lancaster (4), Harrisburg (8); Bethlehem (3); Allentown (1); Scranton (2); Wilkes
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Barre (6); and Williamsport (5) & (2); and, Harrisburg (4). The ALJ, the OTS, the OCA, the
OSBA, and the Company attended each hearing.
The overall attendance (numbers in parentheses) at the hearings does not show a
strong interest in this rate increase, or in the Commission’s processes. The ALJ cannot know or
be sure of the factors that influence attendance at these hearings: location, timing; advance
notice, method of notice, all could play a role. The ALJ also opines that some valuable
information was obtained at these sessions. Moreover, these hearings provide an opportunity for
individual complainants to be heard on their complaints, e.g., Victoria K. Mackin,
R-00049255C0008 testified at the Bethlehem session, and Margaret Stuski, R-00049255, could
have testified at either of the Harrisburg sessions.
The ALJ also notes that numerous letters were received by the Commission and
placed in the Public Comment File that is part of the documents associated with this case. At the
time of the Prehearing Conference, various parties were directed to review this file, and copies
were provided to OCA and the Company. ALJ Colwell reviewed them carefully, and prepared a
summary list of the letters.
OCA presents a summary of each witness’s testimony at each public input
hearing, with the exception of the last session in Harrisburg, without comment. Attachment D,
OCA MB, Vol II
The Company, on the other hand, provides an overview of the public input
hearings, quotes the comments favorable to it, and the satisfactory responses it made to customer
inquiries. It states that it believes that it has shown that it has programs for its poor customers,
that it is expanding, and that it responded to its small business customers. The ALJ did not note
a specific response to small business. It also avers that it addressed other issues raised in the
public inputs in detail. PPLEU MB at 177-179
A representative of the Northeast Democratic Delegation of the House of
Representatives spoke in Scranton on behalf of its members. The representative testified that the
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amount of the increase was excessive, and opposed the PUC's putting in place the DSIC. A
Lycoming County Commissioner spoke in Williamsport. He spoke positively of the Company,
but opposed the increase, noting that it would have a dampening effect on development, and thus
add to unemployment. He noted the 7 % cost cutting effort by the County, and urged that the
Company do likewise rather than seek this increase. A representative of the Borough of
Mechanicsburg spoke in Harrisburg, stated that the Borough has had to pass on substantial costs
to its citizens in the past two years, and asked that the Company receive a smaller or no increase
at all.
The ALJ notes in particular that members of the Pennsylvania Food Merchants
Association appeared and testified at Lancaster and Bethlehem (Witnesses Good, Sload, and
Boyer). These individuals own and operate, or in one case work for an ice cream manufacturer,
small retail operations which must maintain refrigeration 24 hours a day, and lighting for long
hours, sometimes 24 hours a day. At least one testified to reducing usage with new lighting,
nonetheless, all of them will be hit hard by this increase. These witnesses are represented by
OSBA, and would be the beneficiary of its suggestions to reallocate the rate increase.
In addition, members of the minority community in Harrisburg testified about the
desire for more employment opportunities at PPLEU. A number of retired persons opined that
the 8% increase was too high, and should be reduced to 2.71%, or eliminated altogether. Several
testified to the effects of Hurricane Isabel, and the length of time it took to get service restored.
A number of witnesses testified that they believed that PPLEU was financially healthy and did
not need in increase.
In particular, in Williamsport, witnesses were of this opinion, but they were
relying on the PPL Corp. annual report, and they also felt that the PPLEU’s executives’ salaries
were too high. These figures were also for PPL Corp. executives, but a portion of that salary is
allocated to PPLEU, and that information was subsequently provided to that witness. Several
witnesses were still thinking of PPLEU as an integrated utility, and wanted to testify about
generation programs, but the Company’s objections were granted. Also in Williamsport, one
witness noticed that the Company’s original notice included in bills gave an incorrect cut off date
181
for the filing of complaints. The notice included the effective date for the rates, January 1, 2005.
While this is technically incorrect under the regulations, nonetheless, the Commission does not
have a cut off date for the filing of complaints in rate cases, and it is better to have a notice that is
too permissive than one that improperly cuts people off. The request to re-notice the case,
coming as it did in August, was impractical and would have created confusion had it been carried
out.
A firefighter in Harrisburg found the Company’s response to calls to restore
dangerous conditions delayed during Hurricane Isabel.
XIII.
ORDER
THEREFORE,
IT IS RECOMMENDED:
1.
That PPL Electric Utilities Corporation shall not place into effect the rules,
rates and regulations contained in Supplement 38 to Tariff Electric-Pa. P. U. C. No. 201, the
same having been found to be unjust and unreasonable and therefore, unlawful.
2.
That PPL Electric Utilities Corporation is hereby authorized to file tariffs,
tariff supplements or tariff revisions containing rates, rules and regulations, consistent with the
findings herein, to produce revenues not in excess of $669,201,317 or an increase over present
revenues of $144,528,317.
3.
PPL Electric Utilities Corporation is authorized to establish a
Transmission Service Charge (TSC), and the TSC rate shall be initially set at $0.5439 per kWh
for services as set forth in the tariff, and shall be applicable to transmission services purchased
by PPL Electric Utilities Corporation from PJM under the OATT to provide service to its POLR
customers and others requiring the service.
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4.
That PPL Electric Utilities Corporation tariffs, tariff supplements and/or
tariff revisions may be filed on less than statutory notice, and pursuant to the provisions of 52 Pa.
Code §§53.1, et seq., and 53.101, may be filed to be effective for service rendered on and after
January 1, 2005.
5.
That PPL Electric Utilities Corporation shall file detailed calculations with
its tariff filing, which shall demonstrate to the parties’ satisfaction that the filed tariffs the
adjustments comply with the provisions of the final Commission Order.
6.
That PPL Electric Utilities Corporation shall allocate the authorized
increase in operating revenue to each customer class and rate schedule within each in the manner
prescribed in the final Commission Order.
7.
Assessment of interest on TSC overcollections [and undercollections]
shall be calculated at the statutory rate provided for in 66 Pa.C.S. §1308.
8.
PPL Electric Utilities Corporation shall not include language in its tariff
that establishes a Distribution System Improvement Clause (DSIC).
9.
The investigation at Docket No. R-00049255 is hereby terminated, and the
proceedings at Docket No. R-00049255 shall be marked closed.
10.
The complaints docketed at R-00049255C0001, R-00049255C0002,
R-00049255C0003, and R-00049255C0004 are considered satisfied in part and dismissed in part
consistent with this Order; the complaints at R-00049255C0005 to R-00049255C0010, and
R-00049255C0012 to R-00049255C0019 are hereby dismissed, and all the complaint files shall
be marked closed.
11.
The complaint at R-00049255C0011 is dismissed consistent with the
Commission Order at that docket, and the file shall be marked closed.
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12.
That the interventions of IBEW, Allegheny Power, and PECO are hereby
dismissed.
Date: October 21, 2004
Allison K. Turner
Administrative Law Judge
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XIV. TABLES
See separate document number 501239.
185